Pembina Pipeline Corporation (NYSE:PBA) Q2 2025 Earnings Call Transcript

Pembina Pipeline Corporation (NYSE:PBA) Q2 2025 Earnings Call Transcript August 8, 2025

Operator: Good morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation Q2 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, August 8, 2025. And I would now like to turn the conference over to Dan Tucunel, VP Capital Markets. Thank you. Please go ahead.

Dan Tucunel: Thank you, Ina. Good morning, everyone. Welcome to Pembina’s conference call and webcast to review highlights from the second quarter of 2025. On the call today, we have Scott Burrows, President and CEO; and Cameron Goldade, Senior Vice President and Chief Financial Officer, along with other members of Pembina’s senior leadership team. I would like to remind you that comments made today may be forward-looking in nature and are based on Pembina’s current expectations, estimates and judgments. 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 August 7, 2025, for the period ended June 30, 2025, as well as the press release Pembina issued yesterday. All of these materials are available online at pembina.com and on both SEDAR+ and EDGAR. I will now turn things over to Scott.

J. Scott Burrows: Thanks, Dan. Yesterday, we reported our second quarter results, which were highlighted by quarterly adjusted EBITDA of $1.013 billion. We remain on track to deliver full year results within our original 2025 adjusted EBITDA guidance range. But Cam will discuss in more detail, as we are through the halfway point of the year, we have updated the range to $4.225 billion to $4.425 billion. On the project front, Pembina continues to demonstrate its ability to deliver capital projects that provide strong returns and a competitive service offering. The Cedar LNG Project continues to progress according to plan and remains on budget and on time with an expected in-service date of late 2028. We recently celebrated the achievement of a major milestone for the project as construction of the floating LNG vessel began with steel cutting on both the top side facilities and the vessel hull.

Onshore activities are continuing and marine terminal clearing, drainage, erosion and sediment control, pipeline right of way clearing and road upgrades have been completed. The market for LNG supply on the West Coast of North America remains strong, and Pembina continues to progress remarketing of its 1.5 million tonnes per annum of Cedar LNG Project capacity to third parties and expects to finalize these efforts by the end of 2025. The RFS IV project continues to progress towards an in-service date in the first half of 2026. Pembina is pleased that the project is trending approximately 5% under the previous cost estimate with a revised expected total cost of approximately $500 million. On a cost per barrel of capacity basis, Pembina is on track to deliver its expansion 15% to 20% lower than competing projects currently underway, highlighting Pembina’s advantaged service offering.

Looking beyond 2025, strong business fundamentals continue to reinforce our outlook for low to mid-single-digit annual volume growth through the end of the decade across all WCSB products. The outlook is supported by the strong economics and long inventory lives of the Montney formation and oil sands operations. The resilience of our producer customers despite the volatility in commodity prices and the broader economy, new egress projects, including LNG and NGL export facilities and potential oil pipeline expansions, combined with new demand from potential data centres and petrochemical facilities and a more supportive policy environment and momentum towards reshaping Canada’s energy strategy in a way that could unlock Canada’s abundant and diverse energy resources.

Against the backdrop of growing WCSB, Pembina has differentiated itself as the only Canadian energy infrastructure company with an integrated value chain that provides a full suite of midstream and transportation services across all commodities, natural gas, NGL, condensate and crude oil. Our scope, scale and access to premium North American and global markets uniquely positions us to capture incremental new volumes while unlocking new avenues for growth. Pembina’s ability to maintain and grow its position in the rapidly developing WCSB is supported by the recent developments and projects we highlighted in our release yesterday. Pembina continues to strengthen its propane export capabilities and will soon have access to 50,000 barrels per day of highly competitive export capacity for its own and customers’ propane through our own Prince Rupert Terminal and a new commercial agreement with AltaGas for 30,000 barrels per day of LPG export capacity and the current RIPET and future REEF facilities.

In addition, Pembina has approved an optimization of the Prince Rupert Terminal that through increased storage capacity will allow the use of Medium Gas Carrier Vessels. The optimization is expected to expand access to additional global markets with higher realized propane prices while significantly reducing shipping cost per unit, thereby improving netbacks for Pembina and its customers. We also highlighted how Pembina and PGI continue to strengthen their relationship with leading WCSB producers and develop mutually beneficial solutions to support growing production while providing PGI with take-or-pay commitments and ensure the long- term utilization of its assets. PGI recently acquired from Whitecap the remaining 8.3% interest in 3 gas plants in the sales gas pipeline from PGI s Duvernay Complex.

Concurrently, Whitecap entered into a long-term take-or-pay commitment for firm service at the Duvernay Complex and extended long-term take-or-pay agreements previously in place at PGI’s KA plant. PGI has also entered into an agreement with the Montney producer to fund and acquire an under-construction battery and additional infrastructure in the Wapiti/North Gold Creek Montney area. The project enhances PGI’s footprint in the Wapiti region, connecting directly into PGI’s existing Wapiti Gas Plant. The North Gold Creek Battery will be operated by the producer and highly contracted under a long-term take-or-pay agreement. Additionally, Pembina continues to advance more than $1 billion of conventional NGL and condensate pipeline expansions to reliably and cost effectively meet rising transportation demand from growing production.

These expansions include the Taylor-to-Gordondale Project, which will be a new pipeline connecting mostly condensate volumes from Taylor, British Columbia to the Gordondale area; the Fox Creek-to-Namao Expansion, which is a proposed expansion of the Peace Pipeline system that through the addition of new pump stations would add approximately 70,000 barrels per day of propane plus capacity to the market delivery points from Fox Creek, Alberta to Namao, Alberta and other expansions to support volume growth in northeast BC, including new pipelines and terminal upgrades. The growth is secured by long-term contracts underpinned by take-or-pay agreements, areas of dedication across the Montney and Duvernay formations and other long-term agreements that ensure a strong base of committed volumes.

Final investment decisions on the Fox Creek-to-Namao Expansion and the Taylor-to-Gordondale Project are now expected by the end of 2025 and the first quarter of 2026, respectfully. These fully supported demand-driven pipeline expansion opportunities, along with the success we continue to have in recontracting legacy volumes are taking place against the backdrop of increased competition. We remain confident in our ability to continue to grow volumes across our conventional pipeline system. Our northeast BC and Northern pipelines provide a full product integration across all commodities and connectivity, both upstream and downstream. Combined with our marketing and export capabilities, we believe we offer customers the most competitive midstream service offering.

As a reference point, the weighted average contract life on approximately 1 million barrels of firm contracted volumes on Peace and Northern is approximately 7.5 years. Despite the passage of time, this figure has remained relatively consistent over time and has, in fact, increased slightly over the past 2 years, reflecting our successful efforts to blend and extend existing contracts and sign incremental new long-term contracts. Building upon its position as the leading supplier of ethane to a growing Alberta petrochemical industry, Pembina continues to work closely with Dow Chemicals Canada. We are evaluating the various options available to meet our commitment under the mutually binding 50,000 barrel per day ethane supply agreement. Most notably, engineering and commercial discussions are ongoing related to the addition of a de-ethanization tower at RFS III within the Redwater Complex and a final investment decision is now anticipated by the end of 2025.

Finally, Pembina continues to advance opportunities to provide integrated solutions to support an emerging Alberta-based Data Centre. Greenlight Electricity Centre, a partnership between Pembina and Kineticor, is developing an up to 1,800-megawatt gas- fired combined cycle power generation facility and is in active discussions with a data centre customer to commercially underpin the project. Greenlight successfully advanced through Phase 1 of the Alberta Electric System Operator allocation process and through subsequent commercial efforts has secured a sufficient megawatt allocation to achieve a viable scale for this project. In addition to the opportunity to invest in long-term contracted power infrastructure with an investment-grade counterparty, Pembina is well positioned to leverage its existing and future value chain to further support this project.

For example, the proximity of the Alliance Pipeline offers a potentially accretive expansion opportunity to provide significant natural gas supply to the Greenlight Electricity Centre. In summary, the financial results continue to largely track our initial expectations for the year, and we continue to execute our in-flight construction projects and pursue expansions and new initiatives to respond to growth in the WCSB. I will now turn things over to Cam to discuss in more detail the financial highlights of the second quarter.

Cameron J. Goldade: Thanks, Scott. As Scott noted, Pembina reported second quarter adjusted EBITDA of $1.013 billion. This represents a 7% decrease over the same period in the prior year. In Pipelines, factors impacting the quarter primarily included lower firm tolls on the Cochin Pipeline due to recontracting in July of 2024, lower revenue at the Edmonton Terminals, largely related to the decommissioning of the Edmonton South Rail Terminal in the second quarter of 2024, lower interruptible volumes and lower tolls on the Vantage Pipeline, higher volumes on the Peace Pipeline system due to higher contracted volumes and fewer outages compared to the prior period, which was impacted by the planned outages related to the Phase VIII Peace Pipeline Expansion, higher revenue on the Peace Pipeline systems due to increased tolls mainly related to contractual inflation adjustments, higher demand on seasonal contracts on Alliance and higher contracted volumes on the Nipisi Pipeline.

In facilities, factors impacting the quarter included lower volumes due to planned outages at certain PGI assets and ongoing third-party egress restrictions impacting the Dawson assets, higher contribution from PGI, primarily related to recent transactions with Whitecap. In Marketing & New Ventures, second quarter results reflected the net impact of lower net revenue due to a decrease in NGL margins as a result of lower butane and propane prices, coupled with lower volumes resulting from third-party restrictions at the Channahon Facility and planned outages at both the Channahon Facility and the Redwater Complex as well as higher input natural gas prices at Aux Sable. And finally, lower realized gains on crude oil-based derivatives, partially offset by lower realized losses on NGL-based derivatives.

Finally, in the Corporate segment, second quarter results were higher than the prior period due to lower incentive costs driven by a change in Pembina’s share price in the period compared to the second quarter of 2024. Earnings in the second quarter were $417 million. This represents a 13% decrease over the same period in the prior year. In addition to factors impacting adjusted EBITDA, the decrease in earnings in the second quarter was primarily due to the net impact of costs associated with an asset retirement at the Redwater Complex, lower share of profit from PGI as a result of higher depreciation expense due to a larger asset base following the recent transaction with Whitecap, lower other income due to no similar gain to that recognized in the second quarter of 2024 related to Pembina’s financial assurances assumed by Cedar LNG upon positive FID, lower acquisition and integration costs and finally, no similar net gain on acquisitions to that recognized in the second quarter of 2024.

Total volumes in the Pipeline and Facilities divisions were 3.6 million barrels of oil equivalent per day in the second quarter. This represents an increase of 1% over the same period in the prior year, reflecting the net impact of higher contracted volumes on the Nipisi Pipeline and Peace Pipeline system and lower volumes at PGI, Redwater and Aux Sable due to planned outages. Turning to the full year. As Scott mentioned, we updated our 2025 adjusted EBITDA guidance range to $4.225 billion to $4.425 billion. Within our full year outlook, due to seasonal and asset-specific factors, Pembina expects third quarter results to be largely consistent with second quarter results with stronger results expected in the fourth quarter. First, while Pembina continues to benefit from rising utilization throughout its conventional pipeline and gas processing assets that aligns with volume growth across the Western Canadian Sedimentary Basin, revenue volume growth at these assets is expected to be slightly lower than physical volume growth on a percentage basis as customers expand into their contractual take-or-pay commitments.

Second, we anticipate the typical seasonality positively impacting Alliance in the fourth quarter due to the ability to transport higher volumes during colder periods. This is expected to be offset by the impact of the previously announced settlement agreement with shippers. Third, as usual, we expect a significant portion of our integrity and geotechnical costs on pipeline assets in the third and fourth quarters compared to the first half of the year. Fourth, we are forecasting a higher contribution from PGI in the second half of 2025 compared to the first half of the year, including at the Dawson assets due to third-party restrictions impacting the first half of the year and the start-up of LNG Canada benefiting the second half of the year as well as at the Duvernay Complex due to higher second half volumes.

And finally, we are forecasting a stronger fourth quarter contribution from the NGL marketing business relative to the second and third quarters due to typical seasonality of the WCSB frac spread business. We have also revised our outlook for the company’s 2025 capital investment program, including capital expenditures and contributions to equity accounted investees to $1.3 billion, which is a $200 million increase compared to the prior outlook. This update reflects continued progress on previously identified core business initiatives as well as 2 tuck-in acquisitions at PGI, offset by certain projects being under budget. I’ll now turn things back to Scott.

J. Scott Burrows: Thanks, Cam. In closing, we remain focused on delivering value to our investors by best serving our customers, employees and communities. We are looking forward to delivering second half results in line with our full year 2025 guidance, progressing key proposed projects towards final investment decision over the coming few quarters, finalizing our Cedar LNG capacity assignment by year-end and continuing to progress new initiatives like the Greenlight Electricity Centre and related expansion projects within Pembina’s value chain. Thank you for joining us this morning. Enjoy the rest of the summer, and we look forward to meeting with you in person or speaking to you soon. Please go ahead and open up the line for questions.

Q&A Session

Operator: Ladies and gentlemen, we will now begin the question and answer session. [Operator Instructions] Thank you and your first question comes from the line of Aaron MacNeil from TD Cowen.

Aaron MacNeil: I’m hoping that you can just take a moment to address some investor feedback that we’re receiving. There’s sort of this, I don’t know what — I guess, I would call it a death by thousand cuts narrative out there and if I were to sum it up as a theme, it’s really just about different ways where Pembina’s incumbency in the Canadian NGL value chain is being challenged. The theme covers a lot of ground and several specific points, so I can appreciate that it’s difficult to touch on everyone. But how do you respond to that criticism? What do you think it misses, if anything? And what do you see as the sort of unique value proposition for investors going forward?

J. Scott Burrows: Thanks, Aaron. It’s Scott here. There are a few things, I think, that we need to, I guess, level set or unpack on that question. I’ll try to address it at a high level versus kind of going through every specific point. But to me, there’s a difference between fundamentals and temporary noise. And when you have kind of the extensive franchise that we have in maybe midstream space, I’d say the bar is very high, and there’s always going to be something to pick at. When I step back and get out of the noise and kind of look across the horizon at the fundamentals, I firmly believe that our business is rock solid and is driven today as it always has been by customer demand for our services. When you think about the resource in the Montney, it’s unbelievable.

The basin is growing, and it’s full of visible catalysts, whether it’s gas egress through LNG, new LNG exports, Tidewater egress for oil and new avenues to create value for customers, hydrocarbons, whether that’s incremental petrochemical demand or incremental gas to power, there’s a lot of visible catalysts that we see coming at the basin. And when I think about Pembina specifically, I think we’re the only franchise that directly benefits and is involved in all of these catalysts. If you think about them one by one, there’s direct LNG export ownership with the first-of-its-kind partnership in Canada. We have significant LPG export capacity proprietary and in partnership with our midstream peers, as we talked about. There’s local Alberta demand, East Coast starting access and cost-effective unit trains across the U.S. So we really have an unparalleled marketing basis when it comes to LPG.

We hit all markets. We have a significant and growing condensate franchise supporting the oil sands growth, which we continue to see growing with debottlenecks across the system. We’re currently providing gas egress in a constrained environment with access to high-value markets in the Mid-Continent in alignment with long-term shippers. We’re supporting the standup of a world-scale cracker, both through feedstock supply and ancillary midstream services. And we’re continuing to look to extend our value chain and lead the way for our stakeholders and customers. We evolved the midstream sector in the early part of the last decade, building integrated value chain, which is the core of our franchise today. And now we’re continuing to lead the sector through value chain extension initiatives and provide optionality for our customers.

Our competitors are looking to build the Pembina from 8 to 10 years ago, where we’re trying to go to where the balls are going, not where it’s been. What’s undeniable is that the WCSB is growing, and Pembina will capture its share of this growth for the reasons I just mentioned, while continuing to execute on our disciplined customer-supported growth projects in the core business. I think a real-life proof point of that is the $1 billion of visible capital deployment that we talked about for peace capacity today. In a growing basin, we and others are competing to provide value-added services to our producer clients. And on that basis, we are confident in the resilience of our performance. We’re not going to win every barrel that — we know that, but we do believe we’re going to win our fair share.

So the noise, as you mentioned, or death by thousand cuts, it can be a distraction from what’s important. But in my mind, long-term excellence in execution is what’s important and I believe that we have an unparalleled track record in the NGL midstream space. So hopefully, that answers your question. Happy to take any follow-on.

Aaron MacNeil: Yes. I guess just as a follow-up, you mentioned growth across the basin. We saw you bump the capital spend for the year, and you outlined all the growth opportunities. Last quarter, I think Cam mentioned the potential for a buyback. It seems as though maybe the narrative is shifting more to a growth orientation. So maybe you can sort of just give us a sense of your latest thinking around capital allocation.

J. Scott Burrows: Sure. Maybe just to address part of the question. When I think about the capital program, what I think is important is the majority of that capital was due to the bolt-on acquisitions that we made in the quarter as well as the advancement of some of our projects. Recall when we put out the capital release we talked about potential increment. We had a baseline capital and then we had a bucket of incremental capital, should we advance some of our projects and that’s really what this is tied to, we’re advancing projects. I think what’s lost in that mix, and I just want to point out is that is offset by capital savings across our projects as we continue to execute our projects. So I just don’t want to leave the listeners with an impression that, that increase has anything to do with cost overruns. That’s all incremental new growth and is actually offset by cost savings across many of our projects.

Jaret A. Sprott: Aaron, it’s Jaret here, too. And just kind of getting back to your original question, you were talking about some of the noise and maybe misconceptions. I think last week, one of Western Canada’s largest producers came out and talked about some substantial growth terminally and talking about growing their overall production by 200,000 BOE a day in the next kind of 6 years. We view that as extremely positive. And I think all midstreamers should view that as extremely positive, the investment that, that organization is making in Western Canada and the quality of their reserves. There was some — we obviously got some inbounds with respect to margin erosion, et cetera, with respect to some of their announcements.

And that’s where I think that clarity is required is they talked about $1 per BOE that could be captured, but it required them to get to 850,000 BOE a day. And they also talked about how that value creation is split between operating costs, which I have to think is in their camp. They’re doing something different to save OpEx. And then they talked about 50% of that being transportation value creation. That transportation was represented in a BOE basis, so barrels of oil equivalent, not just straight-up liquids. So we only move Tourmaline liquids today. So that could be gas egress value creation, that could be rail value creation, that could be trucking, that could be liquids pipelines, et cetera. So just kind of wanted to chat about that. And overall, I would say, as customers in Western Canada grow physical barrels, typically, their dollar per unit does go down.

That’s not uncommon. And specifically, our northeast BC pipeline, which they are a customer on, that’s a cost of service pipeline and as volumes go up, tolls go down just like any other cost of service pipeline in North America. Lastly, just what I think that a lot of our listeners probably don’t know, in 2022, we announced a fairly large commitment with Tourmaline for a chunk of their northeast BC development. And that long-term deal for pipe and frac, those tolls don’t change. Those are fixed tolls that we offer the customer, and we take pride in giving fixed tolls and providing highly reliable service. So yes, I just kind of want to — that’s some of the noise that I think requires a little bit of clarity but overall, we’re extremely excited about one of Western Canada’s customers growing by 200,000 BOE a day in the next couple of years, so just to provide some color.

Cameron J. Goldade: And maybe I’ll just close it out on your question on capital allocation, Aaron. I mean, listen, I think we’ve been pretty consistent for some time in terms of our approach to buybacks, looking at the relative risk-adjusted economics. Obviously, we’ve been continuing to do that. We’ve talked about our free cash flow profile over the next couple of years, likely staring at a modest amount of free cash flow in 2025 and likely flattish to perhaps offsetting that in 2026 based on the period of the Cedar spend and ultimately looking at it over a multiyear time period. I think, obviously, we continue to take data points and continue to look at the relative economics, and we’ll do that and sort of without signalling our intention either way here today, obviously, it’s something that we talk about sort of every week.

Operator: Thank you and your next question comes from the line of Maurice Choy from RBC Capital Markets.

Maurice Choy: Just wanted to follow up on some of the comments you’ve made, Scott. Given how you’ve mentioned that you are seeing strong WCSB fundamentals and also your confidence in winning your fair share, how do I translate all that to a long-term EBITDA growth rate? Is it about starting with the low to mid-single-digit volume growth through the end of the decade and then there you add on incremental CapEx-driven growth? So just your thoughts on that.

J. Scott Burrows: Yes. Thanks for the question, Maurice. I think from a guidance perspective, at our last Investor Day, we provided our guidance out towards 2026, and that’s the extent of our guidance at this stage. As we move to the end of ’25 and into ’26, we will look to refresh that guidance going forward. So I’m not prepared to give you a multiyear EBITDA guidance outside of what we’ve already publicly disclosed. But from a volumetric perspective, as we mentioned in our prepared remarks and what you’ve heard from us before is we continue to see somewhere in the neighborhood of mid- to high single-digit growth in volumes across the basin, mainly driven by the catalysts that we talked about previously. So no real change from what we’ve talked about previously.

Cameron J. Goldade: Maurice, it’s Cam here. I guess I would just supplement and appreciate history is not always a perfect example of the future. But if you look at history just as one proxy, and you can look across our business, but just focusing on the conventional for a moment because that’s we often talk about as a proxy. You go back 5 years and actually, our growth in that business and the growth in our business overall was always through a combination of volume growth, but also margin. And margin comes from a number of pieces. Obviously, we have some contractual elements to that. We do that through operational excellence and reducing our own cost structure. But as much or more of the growth came from that piece. And so I think as we think about the future, I think we actually see really constructive volume growth as we look out over the next 5 years, perhaps even stronger than we’ve seen in the last 5, depending on product and obviously, egress restrictions.

And obviously, we’re continuing to do the hard work internally to continue to make our service offering more competitive, more accretive and obviously continue to be able to generate value through margin as well. So I would say that partly underpins our view on the long-term outlook.

Maurice Choy: Just to quickly follow-up on that. You said the volume growth is really constructive and stronger than you’ve seen in the last 5 years. You also said generate value through margin. Are you seeing margin as being one where you can maintain margins? Or do you think that margin growth can also potentially come given the competitive landscape?

Cameron J. Goldade: Yes. I think there’s two areas to answer that question. One is, obviously, in the past couple of years, we’ve had a couple sort of meaningful toll resets on some cross-border assets, namely Cochin and Alliance. And obviously, that has been a headwind on the margin side, tough to get away from that. But I think in the rest of the business, conventional business, our gas processing business, our frac business, we’ve done a lot of really solid things and continue to do things. For example, our Prince Rupert announcement yesterday in terms of medium gas carriers, that’s a margin enhancement activity right there. And so we’re looking for ways. Our team is really focused on doing that. And I think, obviously, the business is evolving.

Obviously, competition is greater than it’s ever been. But I think, as Scott said in his introductory comments, we continue to believe that we have the very best franchise across the board. And so that gives us an advantage in terms of maintaining and frankly, growing that margin.

Maurice Choy: If I could just finish off with a comment you made on the press release about evaluating further expansions to support volume growth in northeast BC. I know you have the Taylor-to-Gordondale Project out there right now, but just curious on your thoughts about the long-term competitiveness of Fort Sask facilities versus the existing and new ones in northeast BC, particularly given how some of the propane, butane incrementally setting out a west for export.

Jaret A. Sprott: Maurice, Jaret here. Yes, great question. First off, the competitiveness of Fort Saskatchewan in totality, not just Pembina’s frac, I’d say, is still very attractive. I just — and the reason why I say that is that the majority of the NGLs that come into Fort Saskatchewan today, regardless if it’s Dow, Pembina, Keyera, Plains, et cetera, they’re all coming from downstream of North Pine. — right? So there’s kind of like maybe an imaginary line where products want to come into Fort Saskatchewan and a significant amount of those are coming from Alberta, a very large amount of the NGLs coming from Alberta. So also, then you need to look at the diversity in the rail connectivity. So there’s obviously going to be opportunities at a significantly smaller scale.

If you look at all the C3+ capacity in Fort Saskatchewan compared to North Pine 1, 2 or 3 even, they don’t even compare in size and scale, rail connectivity, inlet storage caverns, et cetera, et cetera. Like there’s a lot of efficiencies coming into Fort Saskatchewan. Further to that, the northeast BC frac, you’re going to be dedicated solely to the West Coast. Now short-term pay arbitrage, they look extremely good and we believe long term, they’re going to be good. But there is — we believe, and I think even some of our competitors have talked to this, there’s optionality in having the ability to go to Sarnia into Conway, into Mont Belvieu and meeting kind of that diversified North American market while having access to the West Coast market.

So are there going to be opportunities to build smaller scale fracs in certain areas? Absolutely, there is. If you’re close to rail and those types of things, if you want to do it at a massive scale, and provide that redundancy and that optionality for diversity, I think customers are going to continue to come to the Fort like they have been for a really long time but it’s not — I’m not saying that there’s not small — niche opportunities.

Cameron J. Goldade: Maurice, it’s Cam. I’ll just pile on one last thing. I think to complement what Jaret said, the analogy would be other products. So whether it’s the natural gas value chain, whether it’s the oil value chain, I mean, obviously, there’s been export market opportunities in both of those. And customers have long chosen to diversify their market egress options for a number of reasons. And one of those is, obviously, market arbs, premium markets do ebb and flow. There’s operational redundancy reasons for that, so I think that’s what we really like about our offering. And obviously, the export piece complemented by the announcements that we made yesterday and obviously, the week before, absolutely enhance that. But we also really like sort of the other pieces of our portfolio and think it’s an incredibly competitive offering and frankly, one that no one else has.

Operator: And your next question comes from the line of Robert Catellier from CIBC Capital Markets.

Robert Catellier: Thanks for the fulsome discussion so far. I want to touch on that last point that you made, Cam, about other products. Exports have been a part of your philosophy for a while now. I’m just curious what your long-term plans are for ethane. Any thought given to eventual waterborne exports of ethane?

J. Scott Burrows: Rob, I think for us, I mean, if we back up and again look at the fundamentals in the macro, there is a significant amount of ethane, not just Pembina, but across the basin being produced and quite frankly, reinjected in the WCSB. So the amount of ethane available here could lead to various options, whether it’s further petrochemical investments within the province or other opportunities. As it specifically relates to ethane, the challenge right now is the location of the ethane and where it’s produced and where it needs to get to. And we do not believe, as of right now, there’s a scalable amount of ethane, call it, in northeast BC to support a pipeline because this would need to be pipelined to the West Coast and the economics just aren’t there yet. So we do believe that it’s an opportunity in the future. But right now, the economics of it look challenged.

Robert Catellier: And then what are your thoughts on how the competitive landscape changes if Keyera completes the Plains NGL acquisition as envisioned?

J. Scott Burrows: Yes. From our perspective, those assets exist today. They exist in Plains in a very competent and very fierce competitor. So from our perspective, not a lot changes in terms of assets that exist today, capacity exists today. So they were owned by a formidable competitor, and they’re going into a formidable competitor’s hands. So not — it’s kind of business as usual for us.

Robert Catellier: And then last one for me. I’m just wondering if you could comment on how the marketing conditions have evolved since your last update? And maybe if you can provide any update to the frac spread hedge book for 2026.

Cameron J. Goldade: Rob, it’s Cam here. I’ll take that. So I guess what I would say is that the frac spread hedge book is substantially on — excuse me, the marketing plan is substantially on plan. If you look at where we are on the NGL side, it’s tracking very close to budget. If you look at propane prices and gas prices, they’ve kind of bounced around. And frankly, that’s in spite of a tonne of variability and a tonne of volatility. In Chicago, obviously, that gas has been a little bit stronger, which has obviously been a net positive for Alliance and obviously, a bit of a headwind for Aux Sable. But sort of net-net, and I think what we have observed is that the crude oil complex has clearly been highly variable. We’re likely seeing somewhat more modest storage opportunities, albeit recognizing that that’s a relatively small piece of the marketing book.

But I think if you take my comments and the guidance update together, we’re sort of talking at the margin. Differentials have obviously been a little bit narrower than they were in the fall. So all those pieces together, I’d say we’re very close to where we were, maybe just slightly lower than budget time. But clearly, I think what we do see as tailwinds is I think if you went back 3, 6 months, we were looking at a stronger AECO strip as we got into the fourth quarter of this year. And obviously, we’ve observed that as months have ticked by here, even following the startup of LNG Canada, obviously, there’s still quite a bit of storage to work through on the Canadian gas side. And so that strength has been pushed out. That is obviously in the near term, supportive of our NGL business.

As far as the 2026 outlook for hedges, you’ll remember that about 2 or 3 years ago, we went to a more dynamic hedging strategy, which effectively involved sort of looking at our own market knowledge, looking at the probabilistic outlook of where the business was and sort of right setting our hedge levels based on that. As we sit looking at 2026 at the moment, we are relatively modestly hedged because we see the P levels sort of at or slightly below a P50 level and so from that perspective, we do see some constructiveness coming, I think, particularly, as I mentioned, in the natural gas space. And so we’ve really opted to defer our hedging probably a bit later than we have in the past because we do believe that there’s some constructiveness to the market.

Operator: And your next question comes from the line of Ben Pham from BMO.

Benjamin Pham: First question on Cedar LNG. Could you talk about your progress on the remarketing? It sounded like there was a qualitative positive tone on it early this year in terms of solidifying something. Can you share progress going forward? Is it more oversubscription versus the capacity? And has it more narrowed in terms of the conversations there?

Stuart V. Taylor: Ben, it’s Stu. Yes, we — the remarketing of our capacity, we’re very pleased with the progress that we’ve made to date. We’ve engaged in multiple counterparties and through that process in time, we have continued to refine our discussions. We are exchanging agreements with counterparties at this point in time and looking to, as Scott already described, finalize definitive agreements in 2025. As far as the capacity, we’ve always had the intention of selling the capacity portion of it and are open to and considering selling the entire 1.5 MTPA. And those conversations have begun and again, are part of what we expect to close at this point in time. Again, there remains tremendous interest in the capacity, and it’s just the effort and details to get through some very large and complex discussions and agreements as we go forward. So we remain optimistic that we’re going to arrive at something that works for us and for our customer.

Benjamin Pham: May I switch over to the Peace. You referenced a 7-year average contract length. And I just wanted to clarify because I was thinking you go back, you had probably some expansions 10 years ago you put in with 10-year take-or-pay contracts. Can you clarify those contracts are probably expiring this year and next, you effectively have extended those contracts or there’s no expirations that you’re dealing with or renegotiating?

Jaret A. Sprott: Ben, Jaret here. You absolutely nailed it. So Scott mentioned, we had about 1 million barrels on the total Peace Northern system, on the conventional system at about 7.5 years. So yes, a lot of those contract roll-offs have been extended with incremental barrels with our customers.

Cameron J. Goldade: And Ben, just as a reminder, I mean, I was just going to say that’s been a multiyear thing going all the way back, frankly, to 2019, 2020 when we started talking about areas of dedication and extensions through that, some of the extensions we’ve done over the past 3 or 4 years. It’s been an ongoing and regular process each year.

Benjamin Pham: Yes. I understand. I was just looking back what you’ve done, it’s all come together now for me. And maybe one last thing, some of the early questions around some of the commentary on your stock and sentiment and stock is down $10 or so over a short period of time. I mean at what point do you actually start to maybe just push down growth CapEx and buyback stock instead?

J. Scott Burrows: Ben, I think as we think about this year’s capital program and next year’s capital program, they’re largely committed in terms of advancing FID projects like Cedar. A vast majority of next year’s capital is Cedar capital as well as pipeline capital. We’ve signed agreements that require us to build and expand the pipeline, so the majority of the capital is committed towards FID projects. But buying back stock versus growth capital is always a constant debate amongst our team here and with our Board. But right now, as we’ve talked about capital is dedicated to projects and the projects we are considering generally enhance our franchise. Buying back stock is a nice economic outcome, but it doesn’t necessarily enhance your franchise and enhance the service offerings that you can provide to your customers, so it’s always a balance.

And of course, as stock prices go down, it increases the discussion as it relates to buybacks. But right now, for this year and next year, the capital program is essentially locked down for existing projects.

Operator: And your next question comes from the line of Jeremy Tonet from JPMorgan.

Jeremy Bryan Tonet: Just wanted to pick up with the AltaGas agreement there. I was wondering if you might be able to expand a bit more on the go- forward, I guess, LPG export strategy? And do you see kind of more partnerships going forward versus growth projects to expand your capabilities? Or just wondering if you could talk a little bit more there on the thought process and what we could expect going forward.

J. Scott Burrows: Well, I think for now, we’re happy with the two announcements that we made today. Obviously, the AltaGas 30,000 barrel a day incremental contract and the investment in our own facility to optimize — for us right now, I think getting the MGCs up and running and advancing that project is a big focus. Like any asset, we will continue to look to optimize that facility. As Cam pointed out earlier, the MGCs are an optimization of that facility. And as we get closer to in service of that, we will again look to optimize that, whether it’s lowering — continuing to lower the cost of that or potentially optimizing shipping and rail, which could increase capacity. So optimizations remain key. And then augmented with our AltaGas agreement, we’re pretty satisfied.

Now that being said, if you listen to our comments around volume growth and pipeline growth, we continue to see growth in the NGL space. And as those NGL volumes grow towards the end of the decade, we will continue to assess where the optimal market is for those barrels. And as Jaret pointed out, it’s always good to have optionality in any product in any marketing because while arbs are open right now, we know that arbs aren’t always open. And so we will look to continue to build out our assets in Fort Saskatchewan. And as we secure more barrels, we will look to where the optimal markets are, and that could be further barrels off the West Coast or it could be to other markets depending on the time and where the markets are open at that time.

Jeremy Bryan Tonet: And just want to pivot towards Project Greenlight, if I could. And it sounds like there’s good, I guess, commercial progress there. I was wondering if you could provide maybe a little bit more color on how that’s coming together. I guess, when you could see more signings or getting closer to visibility on when FID could be possible?

Stuart V. Taylor: Yes. Thanks. It’s Stu again. Yes, as you stated, I think we’ve made tremendous progress on the Greenlight project with our partner, Kineticor. We worked hard as a team and a group to successfully advance through Phase 1 of the ASO allocation process. And with subsequent commercial efforts, the project was able to sufficiently secure a megawatt allocation that will allow a viable scale that the project can move forward. That was very exciting for us. That allocation of megawatts off the grid is a stopgap measure until we can get our facility built, the power generation facility. We’re taking all the steps necessary to progress in all of the elements such that our project could be in service in 2029. And so we’re very excited about that.

And we’re working with — commercially working with the offtaker of that power. They would be in service. The data centre itself would be in service in ’27, consuming that grid power that I just talked about and then switching over to the generated power from our site. We’re having very good conversations with commercially and are expecting to further those through the remaining part of 2025 and are excited about the progress that’s been made.

Jaret A. Sprott: And Jeremy, I’ll just maybe add that with our Alliance press release kind of there late in July with the settlement, we also talked about the expression of interest to expand Alliance kind of that interprovincial short haul and the interest there, that would obviously feed a lot of the gas that would go into Project Greenlight. So the interest there is extremely high. So yes, it’s all coming together.

Jeremy Bryan Tonet: And just a last one, if I could, with regards to Cedar, if you could provide maybe a little bit more color with regards to commercial discussions there as we approach in service, how I guess that impacts the tone of those conversations?

J. Scott Burrows: Yes. I think from where we were a year ago, we are FID-ed, which is obviously a key milestone. We’re a year closer to in-service and the project is real. I mean if we were — as I talked about with the steel cutting has happened, we were up in Kitimat last week and the progress along the terminal and the right of way is tremendous. So that’s garnered real interest from multiple counterparties, which has led to a broader process. And as Stu mentioned, we’ve seen significant interest and we’re very optimistic about getting these deals done here in the next quarter or 2.

Operator: And your next question comes from the line of Patrick Kenny from National Bank Financial.

Patrick Kenny: Just on PGI, on the back of these most recent tuck-ins, I was just wondering if perhaps you could provide a bit more color on what the opportunity set looks like, what else you’re seeing out there in terms of low-hanging fruit consolidation or investment opportunities that you could add to the portfolio? What type of assets or resource plays across the basin look most interesting? And also on the back of that, if you had an update on what the remaining internal funding capacity of the JV looks like going forward, that would be great.

Jaret A. Sprott: So obviously, when we created PGI, there was obviously some extreme like having KKR as a partner, and they’ve been a great partner. It’s been a tremendous outcome. That business has grown tremendously, and it continues. It seems like quarter-over-quarter, Chris and his team are pumping out new integrated deals feeding tremendous value chain. Their strategy really is to focus on, number one, high-quality resource, focus on liquids-rich resource that’s going to feed the Peace Pipeline and into the fractionation complex, et cetera, focused obviously on customers who typically don’t build their own processing infrastructure and batteries and those types of things. So there’s a lot of opportunities out there. Some recent acquisitions, some lands have changed hands and those types of things.

There’s opportunities out there to build new greenfield, but there’s a lot of opportunities for us to expand our existing footprint, like we’re doing work at K3 right now, Wapiti expansion. We did a small expansion at our Hythe complex like so there’s a lot of brownfield opportunities, specifically in the sour gas space. That’s obviously where Western Canada is ultimately constrained is sour gas processing, and we have a lot of it, a big portfolio of it and extensive pipelines that interconnect a lot of that. So those are kind of the brownfield, greenfield short opportunities. With respect to targets or acquisitions, I can’t really speak to that. Obviously, I’d have to have KKR is backing to speak to anything like that. But we’re always looking like we are here at Pembina.

And if the right opportunity presents itself, we will be on it. And maybe I’ll let Cam talk to the financing.

Cameron J. Goldade: Pat, just with respect to funding capacity, I think, obviously, what we’ve seen is that, that JV has been funded with a very supportive credit — bank credit market to date and obviously, consistent contributions from both of the partners. I would say that we’ve got some existing liquidity under the existing arrangements to the tune of a few hundred million dollars under the kind of the existing credit stack. We’ve also got an accordion facility there, which could provide another few hundred million dollars on top of that. And obviously, there’s always other opportunities to look at various markets. So I don’t see funding capacity being a constraint for PGI in the near term. Clearly, I think that JV has done exactly what it was intended to do and the performance from it has been very solid across the board and so continue to have strong access to capital to execute the strategy.

Patrick Kenny: And then I guess, zooming out on a consolidated basis, just looking at the upsized capital budget for the year, might be a bit early here, I appreciate, to give us a sense as to how you’re thinking about 2026. But just wondering, given all the potential projects that are still in the queue, Cam, if you had a sense as to what your internal funding capacity might look like coming out of 2025 based on — now that you’ve firmed up your financial guidance for the year, where you see the balance sheet exiting the year and based on run rate free cash flows?

Cameron J. Goldade: Yes, sure. It’s a great question, Pat. So first of all, I mean, I guess, a reminder that we’ve been pretty clear and pretty consistent over time around our target leverage and our — I guess, our financial theory or our financial orientation, which has always been around a strong BBB rating and ultimately, looking at targeted proportionally consolidated debt-to-EBITDA kind of in that 3.5 to 4x. Obviously, we’ve had the official range kind of up to 4.25% and that’s really meant to capture, frankly, situations that we’re in right now. And I think what I speak to when I say that is, obviously, we’re in the middle of a 4-year build project with Cedar LNG and something that is accruing debt each year, but with no positive EBITDA contribution until late 2028.

And so obviously, that shows up in the leverage metrics. It’d be wrong to disregard that entirely. And so as you’d see our leverage metrics sort of notch up a little bit into 2026, t’s really as a function of that. If you start to back that out, we’re really comfortable in the leverage range of where we are and really square within that target range. As for what the funding looks like, I would say, obviously, I mentioned earlier that we’ve got a bit of free cash flow this year, modest amount based on our current forecast. Next year, we probably are slightly the other way. We’re probably modestly in a deficit position. But on a multiyear basis, I think we are free cash flow neutral to slightly positive based on our 3-year range that we disclosed back at Investor Day last year.

And so that continues to afford us a strong position, I think, as we’ve talked about and the ability to sort of still seize opportunities if and when they come about because of our strong financial position.

Operator: And your next question comes from the line of Theresa Chen from Barclays.

Theresa Chen: As a follow-up to the discussion of the competitive dynamics earlier, given that it does seem to be intensifying, whether that be from traditional midstream players or your customers taking some of these midstream activities in-house. In addition to the level of contracting that you have across your portfolio and the 7.5-year average duration comment, how do your fees compare to alternative options, whether that be the competing pipeline system across your footprint or different mode of transportation to the BC West Coast for export. Can you help us think about the composition of the relative economic alternatives from a customer’s perspective and how your assets stack up?

Cameron J. Goldade: Yes. Theresa, it’s Cam here. I’ll maybe start out. I think a couple of points. One point that we continue to reinforce is capital execution and really why that’s relevant is we think that capital execution from Pembina’s perspective is a strategic advantage. We see ourselves on a dollar per unit basis of capacity, whether it’s in the pipeline or the frac sector being more competitive than our direct competitor. We obviously gave a stat on the frac space. That’s really observable. We’ve looked at other stats for comparable pipeline projects and believe the same sort of directional magnitude is also true. And so we sit there and look out and say, over the long term, we’re in a very strong position to be able to compete and continue to offer competitive fees.

I think the advantage or the dynamic is that all of our tools are posted on our website for our customers and our competitors to see. We don’t have the same specific visibility there with our competitors. I think, obviously, we get into conversations with our customers and are looking to provide the most efficient tools. But from our experience contracting over the past 3 years, we have a sense that we are as equally competitive and obviously have the advantage of being an incumbent and all the connectivity and capital that exists today to serve our customers. And ultimately, we think that, that gives us an advantage.

Jaret A. Sprott: And just further to that, it’s Jaret. I think we talked about — Cam talked a lot about capital tools. When you’re moving a very large number of physical barrels, our customers are very focused on operating costs. So our operating costs amortized over a large denominator, obviously, is a bit of a competitive advantage for Pembina. Also the upstream connectivity, when you’re moving roughly — when we’ve got roughly 1 million barrels under contract, you have a lot of existing assets that are already connected to Pembina’s infrastructure. And to — obviously, some assets are duly connected today, and everyone knows that. And then some assets are — the proximity to alternatives are extremely close, some of them aren’t.

So the capital that’s required, that’s obviously incremental capital from the customers to connect into those pipes. And then when you think about downstream connectivity, we’ve been fairly public about this, that our pipelines connect into multiple condensate delivery points, multiple fractionators, et cetera, et cetera. And the alternatives don’t necessarily do that. So it doesn’t provide the customers’ redundancy. And as you think about LNG growing and that gas needing to flow every day to LNG, you need your liquids to be able to flow. So the redundancy of having a full suite of diversified pipelines like Pembina has and then the redundancy that all of our pipelines connect into multiple receipt points in the Edmonton and Fort Saskatchewan market, it provides those customers that redundancy to make sure that, that gas can flow every day and to keep obviously, their cash flow streams going.

And then just the torque we have on the size and scale of our infrastructure, the optimization we can do with respect to adding a pump station and/or just optimization through technology on pushing the limits of our assets can provide some pretty high margin and needed space for our customers.

Theresa Chen: Turning to the regulatory front. As Canada sits at an inflection point of reshaping its energy strategy, maybe for decades to come and given that Pembina has a front row seat here, can you tell us about the progress you’re observing either at the federal or provincial level?

J. Scott Burrows: I would — obviously, the words coming out of Ottawa and the provinces are generally optimistic around future energy growth. To me, one of the challenges that as an industry we face is due to the regulatory and political environment for the last decade, there hasn’t necessarily been a significant amount of, say, greenfield projects being engineered to go to the West Coast, so we’re kind of starting from scratch. But I think what we’re hearing from the government is relative support for industry to start to assess some of those situations. We continue to believe incremental LNG is going to be needed off the West Coast and that, that is a very logical outcome. As it relates to the discussion around crude oil pipelines, it’s interesting to talk about a pipeline, but if you still have an emissions cap at a tanker ban, that obviously is a huge impediment to a new oil pipeline.

So there’s certainly lots of things that need to be worked through but we are positive in terms of what we’re hearing and what we’re seeing in the reach out the industry. I just think it’s complicated and it’s going to take some time to work through the system.

Operator: And your next question comes from the line of Robert Hope from Scotiabank.

Robert Hope: Just one for me. The MD&A specifically referenced that the supply agreement for Dow is mutually binding. How have the discussions on the supply agreement changed just given the recent commentary from Dow and the delay there? And is it the expectation that the agreement will come into effect regardless of when the crack rector service?

Cameron J. Goldade: Sorry, Robert, did you say B discussions?

Robert Hope: The discussions.

Cameron J. Goldade: Oh! The discussion, sorry. I think, obviously, we’ve been working very closely with Dow on that. And obviously, they’re analyzing the project and ultimately sort of rightsizing the spend profile. What I would say is that we had a tour of our Redwater asset in July. And I think the group there sort of went past the work site and I think speaking for most of those people, they were very pleasantly surprised to see the amount of activity that was still ongoing at that site, not speaking for Dow, but it was clear that there was a tonne of activity still ongoing. I think you’re correct in the words chosen, there’s a mutually binding supply agreement there that with an agreement on our part to sell and on their part to buy 50,000 barrels a day of ethane, it’s pretty clear.

Operator: And your next question comes from the line of Sumantra Banerjee from UBS.

Sumantra Banerjee: Just one for me. So another one related to power generation and Greenlight, if you’re looking at any other opportunities, would you like to do them more similar to a partnership as you would with Greenlight or just more detail on potential future opportunities?

Cameron J. Goldade: I’m sorry, could you repeat the question? We had a hard time hearing.

J. Scott Burrows: Actually, we just didn’t hear the first part of the question. Apologies.

Sumantra Banerjee: Okay. All good. Yes. So just wanted to ask about potential future power generation opportunities and if you’d follow a similar strategy with partnerships such as Greenlight or any other details that you could provide?

J. Scott Burrows: Yes. I think for now, we’re not focused on future power opportunities. We’re really happy with our JV with Kineticor and really focused on getting this potential data centre opportunity up and built. If we are successful and we FID, we’ve talked about this being multiple phases and a significant amount of capital and therefore, solely focused on this as it stands today.

Cameron J. Goldade: And just as a reminder, I mean, the rationale for this specific project was obviously the integration with all of the other elements of our business, the location of it, the fact that it’s based around our Fort Saskatchewan land position, the opportunity to enable a CO2 solution, the opportunity to enable gas egress on both our processing business and hopefully, Alliance. So this was a really sort of hand-in-glove kind of opportunity for Pembina, which is why we thought it was interesting to pursue.

Operator: And your next question comes from the line of Praneeth Satish from Wells Fargo.

Praneeth Satish: I guess you kind of touched on this, but I just want to put a pin on it, I guess. So as we bridge from 2025 to 2026 EBITDA, maybe if you can just frame the moving pieces. So I guess on the — you did give the guidance at the Analyst Day, but we now have the Alliance rate case, maybe something on the U.S. side, maybe marketing a tad weaker. But then on the tailwinds, you’ve got a bunch of new projects, mid-single-digit volume growth. So I guess just kind of net-net, putting that together, should we expect positive EBITDA growth in 2026? Or is ’26 more flattish and then the growth kind of resumes in ’27?

Cameron J. Goldade: Praneeth, it’s Cam here. I guess what I’ll sort of speak to is the guidance that we’ve got out there today, which is obviously a fee-based guidance. Obviously, we would continue to see positive fee-based guidance — or excuse me, positive fee-based growth into 2026. I think we would have — we were trending very, very strongly on that. Obviously, the alliance settlement is an unavoidable setback to that for 2026. And so we can’t ignore that. Outside of that, I think we’re doing a tremendous amount of work, and we do see visible growth opportunities in the rest of the fee-based business. And the team, I can tell you the focus of our team really starting from a few months ago until now has been on opportunities for 2026 and adding value and new opportunities.

So we feel constructive about 2026. The marketing business will be what the marketing business will be. And I think — I would point that despite the fact that it is a commodity exposed or commodity- related business, the history of that business has been confined to a relatively narrow range over time. I mean, if you looked at the last 2 years on an apples-to-apples basis, there’s probably a couple of hundred million dollar range there in most years. So it will be what it will be, and we can probably get more pointed on that as we get closer to setting our guidance towards the end of this year. But would point to the fact that we continue to reiterate our 4% to 6% fee-based EBITDA per share guidance through 2026 and are obviously working hard on that.

Praneeth Satish: And then I know you kind of touched on this with the prior question on the Peace Phase 3 and Phase 4 contracts that expire soon. But can you give any more clarity, I guess, on how much of that capacity has been blended and extended? You gave the 7-year average duration, and I think you said that a lot of it has. But maybe just can you get a little more granular? Have you recontracted over 50% at this point? Just trying to get a sense there. I know it’s a competitive process. And then tied to that, I guess, on the Fox Creek-to-Namao Expansion, are you looking to kind of blend and extend some more of those legacy contracts with that expansion.

Cameron J. Goldade: Yes. I’d say, first of all, Praneeth, I mean, you can obviously appreciate that it’s a competitive market out there. I think, obviously, we’ve been pretty transparent for a lot of years on our disclosure. And so the fact that the weighted average life has extended from — really from 7 years a couple of years ago to 7.5 today kind of just purely mathematically has to tell you that a meaningful portion of that has been recontracted. I would also remind you that contracts do not equal capacity. That — those 2 are independent. Capacity came over time and obviously, a big — there was a swath of contracts that came with Phase 3, subsequent to that, there have been debottlenecks, and we’ve been adding contracts over time. So to the earlier points, we continue to push that recontracting out over time based on our service offering.

Jaret A. Sprott: And just to follow up on your last question on Fox Creek-to-Namao specifically. If you take a look back and you look — and you break down the entire suite of products that Pembina has, we obviously — Scott referenced the 1 million barrels, but that’s broken out between crude, C2+, C3+ and C5+. And as you probably are well aware, Pembina has a segregated system of bringing those products into the Edmonton and Fort Saskatchewan markets. So with the increased demand and with obviously increased NGLs coming at the system as part of that single-digit growth — mid-single-digit growth that we’re seeing here in Western Canada, we’re really seeing an uptick on the C3+ volumes. And so the specific Fox and Namao, like just if I just looked into northeast BC alone, we’ve seen material recontracting, we’ve seen — we’ve been public about 3 large Montney producers.

And I think one of the things you need to look at is the producers that we have under contract that we’ve been public about, of those 3, we’ve talked about Conoco and Tourmaline. But if you look into kind of go Edmonton West, we’ve been public about our previous Chevron, KUFPEC, now CNRL KUFPEC, 20-year area of dedication. I think through PGI, we’ve talked extensively about these long-term fully integrated deals and we’ve essentially captured a significant amount of all the volatile oil Montney window and the very liquids-rich Montney oil or Montney windows. So there’s a lot of NGLs coming at us. And the reason I’m pointing that out is that when we see a constraint on a certain aspect of our system, that’s where we need to deploy the capital.

So that capital, there wouldn’t be a blend and extend. These are new contracts that our customers are taking to get their C3+ into Fort Saskatchewan. And so it wouldn’t be like kind of a stand-alone project. It’s in the need and necessity of customers’ demand.

Operator: There are no further questions at this time. I will now hand the call back to Scott Burrows for any closing remarks.

J. Scott Burrows: Thank you for your time today. And as I said previously, I hope everybody has a great summer. Thanks, everyone.

Operator: And this concludes today’s call. Thank you for participating. You may all disconnect.