Pembina Pipeline Corporation (NYSE:PBA) Q2 2024 Earnings Call Transcript

Pembina Pipeline Corporation (NYSE:PBA) Q2 2024 Earnings Call Transcript August 9, 2024

Operator: Good morning ladies and gentlemen and welcome to Pembina Pipeline Corporation Q2 2024 Results Conference Call. At this time, all lines are in listen only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Friday, August 09th, 2024. I would now like to turn the conference over to Dan Tucunel, VP of Capital Markets. Please go ahead.

Dan Tucunel: Thank you, Joanna. Good morning everyone. Welcome to Pembina’s conference call and webcast to review highlights for the second quarter of 2024. On the call today we have Scott Burrows, President and Chief Executive Officer; Cameron Goldade, Senior Vice President and Chief Financial Officer; along with other members of Pembina’s leadership team including Jaret Sprott, Janet Loduca, Stuart Taylor, and Chris Scherman. 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 MD&A dated August 08, 2024, for the period ended June 30th, 2024, as well as the press release Pembina issued yesterday. All of these documents are available online at pembina.com and on both, SEDAR and EDGAR. I will now turn things over to Scott to make some opening remarks.

Scott Burrows: Thanks Dan. Another strong quarter was highlighted by record adjusted EBITDA of $1.091 billion, record adjusted cash flow from operating activities of $837 million, and record adjusted cash flow per share of $1.44. Record results were driven in part by the closing of the Alliance Aux Sable acquisition, effective April 1, as Pembina benefited from increased ownership in those assets. Both Aux Sable and Alliance have been performing well and we are excited to welcome new employees to the Pembina team. With the release of our second quarter results yesterday, we were also pleased to announce that we have acquired the remaining 14.6% interest in Aux Sable U.S. operations from Williams, effective August 1. Since the Williams Aux Sable acquisition and the Aux Sable assets have been outperforming Pamela’s expectations and we are pleased to now have fully consolidated ownership of all Aux Sable assets, thereby further simplifying corporate reporting and enhancing the ability to pursue long-term opportunities.

Pembina’s business continues to deliver exceptional results. Volume growth across the Canadian Energy industry is leading to higher volumes in our pipelines, gas plants and fractionators. And while we would prefer to see higher natural gas prices for our producing customers, the current weakness along with robust NGL pricing and strong oil prices, is leading to continued strength in Pembina’s marketing business. Given the strong year-to-date results, the incremental benefit of the latest Aux Sable acquisition and our outlook for the remainder of the year Pembina has raised its 2024 adjusted EBITDA guidance range to $4.2 billion to $4.35 billion, which at the midpoint represents $100 million increase over the previous range. Finally, the second quarter was further highlighted by three other exciting developments.

The first was the positive final investment decision on the Cedar LNG project. We are excited to be moving forward with a project that will deliver industry leading, low carbon cost competitive Canadian LNG to overseas markets and contribute to Global Energy Security while delivering jobs and economic prosperity to the local region. The Cedar LNG projects align squarely with Pembina strategy, offers attractive economics and is supported by a contracting strategy that prudently mitigates cost risk. The second was PGI’s transaction with Whitecap Resources, which included the acquisition of a 50% interest in Whitecaps Kaybob Complex and an obligation to fund further Lator area infrastructure development. We also signed long-term take or pay agreements on Pembinas pipelines and fractionators.

The deal is another example of PGI and Pembina’s ability to provide unique and value added solutions to support the growth demands of our customers. And the third was bringing the Phase VIII Peace Pipeline Expansion into service, marking the culmination of more than ten years and more than $4 billion expansion program that was driven by growing customer demand for transportation services to support development in the WCSB, including the Montney, Duvernay, and other resource players. The Peace Pipeline system plays an important role within Pembina’s integrated value chain and I would like to thank our many customers, employees and communities that have supported Pembina to deliver this major infrastructure build out. As a result of the expansions and ongoing optimization efforts, Pembina is confident that its extensive pipeline network is best positioned to capture future volume growth and allow the Company to continue to offer customers unparalleled advantages through safe, reliable, flexible, and cost-competitive service together with differentiated market access.

I will now turn the call over to Cam to discuss highlights for our second quarter.

Cameron Goldade: Thanks Scott. As Scott noted, Pembina reported record second quarter adjusted EBITDA of $1.091 billion. This represents a 33% increase over the same period in the prior year and remaining at 21% increase adjusting for the Alliance Aux Sable ownership. In Pipelines, factors impacting the second quarter primarily included higher adjusted EBITDA from Alliance due to stronger asset performance combined with increased ownership following the Alliance Aux Sable acquisition, the northern pipeline system outage and wildfires in the second quarter of 2023, which had an impact of $29 million with no similar impact in the second quarter of 2024, contractual inflation adjustments on tolls and the earlier recognition of take or pay deferred revenue on the Peace Pipeline System and the reactivation of the Nipisi, pipeline in the third quarter of 2023.

In facilities, factors impacting the second quarter included the inclusion within facilities of adjusted EBITDA from Aux Sable following the alliance Aux Sable acquisition, the northern pipeline system outage and wildfires in the second quarter of 2023, which had an impact of $18 million with no similar impacts in the second quarter of 2024 and higher interruptible volumes on certain PGI assets. In marketing and new ventures, second quarter results reflect the net impact of increased ownership interest in Aux Sable following the Alliance Aux Sable acquisition as well as higher NGL margins at Aux Sable, higher margins from the Western Canadian NGL marketing business due to higher marketed volumes, lower natural gas prices and higher propane, butane and condensate prices.

Realized losses on NGL based derivatives compared to gains in the second quarter of 2023, partially offset by higher realized gains on crude oil based commodity related derivatives, as well as higher general and administrative expense. Finally, the corporate segment was largely unchanged. Earnings in the second quarter were $479 million. This represents a 32% increase over the same period in the prior year. In addition to the factors impacting adjusted EBITDA, earnings in the second quarter were impacted by unrealized losses recognized by PGI on interest rate derivative financial instruments compared to gains in the second quarter of 2023. Gains associated with the de-recognition of the provisions related to the financial assurances provided by Pembina, which were transferred to Cedar LNG following the positive FID in June.

Larger unrealized losses on renewable power purchase agreements an unrealized loss on NGL based derivatives compared to an unrealized gain in the second quarter of 2023, higher depreciation and amortization, net finance costs, and acquisition and integration fees. Pipeline volumes of 2.7 million barrels per day in the second quarter represent an 11% increase compared to the same period in the prior year. The increase was primarily due to the increase in ownership interests in Alliance, higher volumes on the Peace Pipeline System resulting from earlier recognition of take or pay deferred revenue and the impact of the Northern Pipeline system outage and the wildfires in the second quarter of 2023, combined with the reactivation of the Nipisi pipeline.

Facilities, volumes of approximately 0.9 million barrels per day in the second quarter represent a 14% increase compared to the same period in the prior year. The increase was primarily due to Aux Sable volume recognition following the Alliance Aux Sable acquisition, higher volumes at younger as the second quarter of 2023 was impacted by the Northern Pipeline system outage and the wildfires combined with higher interruptible volumes on certain PGI assets. Turning to our outlook for 2024, in addition to raising our 2024 adjusted EBITDA guidance, as Scott mentioned previously, Pembina has also revised its 2024 capital investment program to $1.3 billion. The revised outlook reflects an approximate $140 million net increase when compared to our original 2024 budget of $1.16 billion, inclusive of then unsanctioned additional growth capital.

Drivers of the increase primarily include the sanctioning of PGI’s Wapiti Expansion and K3 Cogeneration Facility; other increases in revenue generating capital within Pipelines; and additional non-recoverable sustaining capital. The revised capital investment program reflects approximately $300 million for contributions to equity accounted investees, including $240 million of equity contributions to Cedar LNG incurred in the first half of 2024 with no further contributions to Cedar expected in 2024. Pembina continues to expect the capital program to be funded with cash flow from operating activities net of dividends, maintaining its strong balance sheet. At June 30, based on the trailing 12 months, the ratio of proportionally consolidated senior debt to adjusted EBITDA was 3.6 times, which is at the low end of our target range.

It’s important to note, however, that given the April 1 closing date of the Alliance Aux Sable acquisition, the ratio includes all the debt associated with the transaction, but is currently only capturing one quarter of EBITDA contribution. On a normalized basis, this ratio would be approximately 3.3 times. I’ll now turn things back to Scott.

Scott Burrows: Thanks Cam. In closing, I’d like to reiterate that for all of us at Pembina, it has been a strong first half of 2024 and we are looking forward to continued strength throughout the remainder of the year. Amidst the backdrop of industry momentum and an expectation of robust volume growth, we continue to see increased utilization across our systems, pursue many opportunities to accretively invest capital, and execute our strategy within our financial guardrails. Thank you for joining us this morning and for your continued support. Operator, please open the lineup for questions.

Q&A Session

Operator: Thank you, ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] Your first question comes from Jeremy Tonet at JPMorgan Chase. Please go ahead.

Jeremy Tonet: Hi, good morning.

Scott Burrows: Morning Jeremy.

Jeremy Tonet: Just want to dial in on the acquisitions a little bit more. Aux Sable alliance here it seems like they’re outperforming our expectations and just wondering if you could talk a bit more, I guess, about the outperformance in really curious about looking forward. I guess it seems like full ownership would bring new opportunities to Pembina and how that kind of impacts, I guess the marketing opportunities as well. Just any more color on how we should think about what’s possible there going forward.

Scott Burrows: Jeremy, a lot of the strength really was driven at the Aux Sable level. Obviously, the low gas price and high NGL prices had a strong impact on that business. As we pointed out in our comments, we’d obviously like a little higher gas price for all of our producing community and hopefully add to increased drilling. But in the short term here, that low gas price has really led to strong frac spreads across the business, especially at Aux Sable. When you go back to our acquisition, presentation and thesis, we talked about some of the longer term synergies more towards the end of the decade. And we think having full control of Aux Sable will allow us to continue to capture those and give us a leg up in terms of capturing those. It’s a little too early to start talking about what exactly those are in terms of where we’re headed, but we’re actively working and planning on those today.

Jeremy Tonet: Got it? Fair enough. Thank you for that. In the release, I think there’s language that highlights the expectations for 6% and 4% conventional and gas processing volume growth, respectively, in 2024. I’m just wondering, is this a similar trajectory you kind of see in the near term post 2024 in general, at a high level? And I guess my question is, if you’re expecting kind of the mid-single digit growth, is this filling latent capacity on the system, or is this more capital intensity, effectively, how much capital investment will be required to attain that kind of mid-single digit growth, mid cycle as could be possible?

Jaret Sprott: Hey, Jeremy, it’s Jaret here. So first I’ll talk a little bit about what we’re seeing kind of in 2024 with respect to our conventional volume growth. And then I’ll touch on PGI just for a second. So you saw in our, I think in our press release, we dropped it from roughly 9% to 6%. That really equates to approximately, it’s not that much material amount of volume, it’s roughly 30,000 barrels. And what we did see in the first half of the year, which you’ll probably recall from the previous quarters, was we saw a significant reduction in volumes in January here in Western Canada with some extreme weather that obviously set a lot of our customers back, and they really didn’t, really didn’t make that up. We saw a larger turnaround season kind of in that May, June than we expected from some of our third parties.

All of the PGI turnarounds went as expected, and the Phase VIII went that commissioning went extremely well. And then we had a short unplanned outage at our Frac complex, specifically RFS I, that restricted some C2 plus volume. So that’s a big portion of the overall reduction. And then the latter half of the year, across a couple of hundred receipt points in the conventional system. It’s really just timing of development that we’re seeing from our customers. It’s not that they’re not drilling in these liquid rich areas, it’s just that forecasting of when the volumes are coming on, that kind of leads into there’s been some public disclosure recently around some drier gas either being shut in or not completed. We’re not really seeing the effects of that.

As you know, the majority of our PGI assets, all of our PGI assets, they produce significantly liquids rich gas. And you’re actually seeing that in the overall revenue volume increase in PGI. I think we talked from 3% to 4%, 4% to 5%. We’re seeing, and we haven’t brought on any new gas plants. So we’re seeing really strong gas growth where we have lots of condensate and lots of NGLs, which is extremely positive. And I think one of the features of our footprint is that we don’t process a lot of the drier gas. With all that said, our overall thesis for Western Canadian liquids growth hasn’t really changed in that mid digit as we think about latent capacity versus expanded capacity when you’re in Alberta now that Phase VIII is in service, kind of Gordondale follow the map all the way down to Fox Creek into Edmonton, that’s going to be latent capacity use and or pump station.

No more linear assets required to get those volumes into the Edmonton market. And then as you go west of Gordondale into Northeast BC, that’s where we’ll require some incremental pipelines, etcetera. So that’s kind of the distinction. And that’s kind of all been built into our three year capital forecast and all part of our three year cash flow per share guidance that we gave at investor day. Anything else to add, Kim or Scott?

Jeremy Tonet: So maybe just, I guess, mid cycle CapEx or near term CapEx run rate levels? Any high level thoughts there? Is there more processing CapEx that’s required to kind of hit that mid-single digit growth?

Scott Burrows: Hey Jeremy, I think I’d sort of go back to our message from investor day, which was if you sort of look at this year, next year, we’re probably running right around that free cash flow neutral level. So the levels that you’re seeing in 2024, 2025, it’s somewhere in between that billion to billion in a quarter range is probably the run rate for the next couple of years, assuming we continue to execute on the plan and the projects that Jaret outlined. As Jaret mentioned, obviously a big part of that is, is obviously completing RFS IV, which comes into service in the first half of 2026. And likewise, as we continue to move forward and build out that Northeast BC Capital, Northeast BC Transportation Capital that Jaret referred to, that’ll be in that same timeframe as well, providing that all sort of goes ahead with that.

So and then once you get to the sort of the 2026 timeframe outward, obviously the base core business capital starts to trail off as some of those assets come into service. Our BD teams are obviously very hard at work, and we continue to see opportunities. But for the next couple of years, I think that’s probably the way we’re thinking about it.

Jeremy Tonet: Got it. That’s very helpful. Thank you.

Operator: Thank you. The next question comes from Praneeth Satish at Wells Fargo. Please go ahead.

Praneeth Satish: Hi, all. Thanks. Good morning. Maybe just on Cedar, if you can give us an update here in terms of reassigning the capacity that you hold with third parties, are you seeing strong interest from customers there? What’s the timeline to announce that contract? And also, how committed are you to kind of reassigning that entire 1.5 mtpa and could you keep more of it and end up marketing more than 0.3 mtpa with your marketing group?

Stuart Taylor: Hi, it’s Stuart. So we’re now following the FID announcement and progress. We are ramping up our marketing efforts, looking at the remaining capacity of Cedar. I will say that as our project became more real with the FID announcement, our interest is high. We’ve been working with a number of potential off takers that we’ve had conversations for a long period of time, but we do have some renewed and new interest coming in as well. So we’re excited and optimistic of progressing those conversations to completion with a target to have as much of that completed in 2024. So we’re optimistic and excited and continue to make progress with potential offtakers.

Praneeth Satish: Got it. And maybe just switching gears and moving over to the Bakken. I have two questions here on the Vantage pipeline. First, if you can remind us what the utilization is on the pipe and whether Vantage can be expanded any further with pumps. And then secondly, to the extent that there is excess capacity and it can be expanded at a low cost, can you satisfy all of your Dow ethane contract with Vantage? I guess what would the cost be of moving Ethane on Vantage versus some of the other options that you’re considering?

Scott Burrows: Good morning. Thanks for the question. So, yes, we currently do have some wide space on the Vantage pipeline that is capable, obviously, of bringing more ethane up into the [Indiscernible] system and then into the petrochemical feedstock takers there in Western Canada. With respect to our portfolio, with respect to Dow, we’re kind of taking a more diversified approach to this. We think of it as ethane that comes out of our RFS complex, that is C2 plus being extracted in Western Canada and then broken into its parts and fed into the frac here. In Alberta, there is the C2 extraction component that’s more like mainline extraction, like our Empress [ph] or younger facilities that feed straight ethane into the system, into the crackers.

And then you have the Vantage system that can bring product up from North Dakota. So across those kind of three portfolios right now we’re just evaluating what’s the best use of capital to basically fulfill our entire Dow commitment. So we won’t really specifically talk to where the majority of that capital is going to go right now. I think at Investor Day, we talked about here in the next couple of quarters, we’ll be able to provide some more insight on where that capital would be going, but Vantage is definitely a part of the overall portfolio of consideration to meet that contract.

Praneeth Satish: Got it. Thank you.

Operator: Thank you. Next question comes from Patrick Kenny at National Bank Financial. Please go ahead.

Patrick Kenny: Hey, good morning, guys. Just maybe quickly on the Alliance and Aux Sable consolidation. I know there’s some accounting noise in there, but maybe you can just walk us through the headline, $600 million loss on disposal of your equity interest, and maybe what that means for your corporate effective tax rate going forward.

Cameron Goldade: Hey, Pat, it’s Cam here. You just made our accounting teams day with the question. It’s not a really straightforward explanation, other than to say that the accounting standards are pretty clear about how you have to treat a step acquisition. You basically have to act as if you’ve disposed what you’ve got as the equity accounted investment, and then realize the entire fair value acquisition like you would any other acquisition. So obviously, you do the fair value on the existing interest and mark that to market. Obviously. I think what’s important in recognizing that accounting is that there’s an offsetting deferred tax recovery on that de-recognition, which effectively nets you to about zero or so. It’s about a $9 million gain when you net those two out.

And then obviously, then you go forward and you consolidate. And then with the consolidation, now, obviously we own 100% of Alliance and now 100% of Aux Sable. But in Q2, obviously, there was a small non-consolidated interest on Aux Sable, which just gets netted out the back end.

Patrick Kenny: Great. And then I guess going forward, just any impact positively or negatively on the effective tax rate?

Scott Burrows: Yes, I think there will be some positive effect on the effective tax rate. As you’ve seen, there is some benefit to the acquisition, potentially the larger acquisition as a result of some opportunities in the U.S. And so we do get a benefit there. And I think that shows up in terms of the updated tax guide. So you’ll see it come down ever so slightly.

Patrick Kenny: Okay, great. Thanks for that. And then maybe just on the cost pressures here you’re experiencing on RFS IV, maybe you can just walk us through some of the scope changes that might be embedded in that new budget. And then also, just given construction activity, really picking up here for large scale projects in the Heartland area, just how we should be thinking about your ability to lock in costs from a labor productivity standpoint.

Jaret Sprott: Great question, Pat. So think of the project increase kind of in the following three buckets. The first bucket being project scope changes and design modifications. This is really to enhance the, the overall operability of RFS IV specifically, and the overall complex as you know, like we can spread molecules to any one of the fracs. And it’s specifically to accommodate a wider range of C3 plus feedstock composition. So depending on where your customer, if your customer is extracting NGLs from, from a deep basin well, versus a very, oily Montney well, you get a wide range of NGL composition. So this, we made a decision just to enhance the overall operability, to have a wider range, to take that product composition.

The second bucket is we saw some incremental inflation over and above what we expected in the latter half of 2023, when obviously there was a very large project sanctioned in Alberta here. So that was unexpected and caused some of the increase. Then the third bucket is our decision. When we sanctioned this project in February of 2023, it was going to be a typical Pembina project where we do all of the oversight and the execution. And as we saw these labor concerns, as you identified the Heartland area getting busy, we decided to move to a lump sum to make sure that we could procure a Tier 1 contractor that we were confident could get the fabrication shop space, make sure they had access to high quality labor, make sure that they were going to execute with respect to our safety expectations and values, indigenous content, and deliver a high quality project on time.

So we’ve shifted roughly 70% of that total project, as we stated, to a lump sum. We’ll execute kind of more of that outside the lease boundary, outside the frac area. We’ll do a lot of that execution, but we have made that shift. And we did see with shifting that risk from yourself to a third party who’s going to deliver that high quality labor and safety expectations, there is a little bit of a cost with that. So that’s kind of how we break up those three buckets. And overall, the project, like we said, is still planned on being delivered on time, which is great. And then with respect to the commercial side, with this project coming out of the ground as we speak, we’ve been able to secure incremental contracts at the overall base complex, RFS I, II and III, which is obviously great for business.

And then we’ve secured a lot of new contracts over and above our original base case when we sanctioned this with the board in February of 2023. And with the incremental cost, we have seen that the overall sanction metrics have actually gone up. And then with respect to the overall portfolio, I’ll just talk the Heartland is seeing a little bit of increase, but overall, our portfolio is still of projects, is still industry leading, and we have the full confidence in our team to continue with the current projects to deliver on time, on budget and the future ones.

Patrick Kenny: Okay, that’s great color, Jaret, appreciate that. And maybe just real quick, were the incremental costs here contemplated when with the PGI Whitecap transaction as well? In other words, like the all in economics of the deal, I know some of it has some downstream benefits embedded in the returns. Just wondering if those returns are still in line with your expectations with the new costs on RFS IV?

Jaret Sprott: Absolutely.

Patrick Kenny: Yes. Okay, I’ll leave it there. Thank you.

Jaret Sprott: Thanks, Pat.

Operator: Thank you. Next question comes from Rob Hope at Scotiabank. Please go ahead.

Rob Hope: Morning, everyone. I want to follow up on the, on the frac discussion. I guess two parts there. First one is, are the incremental contracts that you signed on for the entire RFS complex reflective of the incremental capital for RFS IV? And then how much Whitespace do you have at RFS? And kind of when could you need some incremental capacity beyond what you’re building?

Scott Burrows: There’s, there’s limited Whitespace, Rob, at the complex, and even with RFS IV coming into service. So right now very focused on project execution of step one with respect to the execution teams. But obviously the commercial teams are in constant conversations with our other customers. And it’s a balancing act between ensuring that we have the base load of the first three fracs, long-term contract extensions, fill four under long term deals, and then get focused on sanctioning number five. But right now it’s really focused on number four and getting that customer interaction for five going. I’d say that’s a little bit further out. With respect to your first question, I think you were asking about incremental contracts. Has anything changed specific due to the, the cost increase? Is that accurate?

Rob Hope: Yes. Like, are the incremental, were fees adjusted up for the new capital cost and that’s how returns were put back on side?

Jaret Sprott: Yes, it’s a combination of — it’s specifically, it’s a combination of volume fees and then you also have the downstream auxiliary fees such as rail loading and terminaling, etcetera. And then obviously the marketing business as well. Some customers choose Pembina to do their full suite of marketing, and some customers obviously do their own marketing, but we are advancing a lot of that business. And then you’re obviously seeing the upside through the marketing arm as well.

Rob Hope: All right, thanks for that. And then maybe just switching over to the ethane opportunities that were highlighted at the investor day, how are those progressing? And then just given the — we’ll call it a tightening labor market in the Heartland, could this de-emphasize an RFS III DS and kind of focus more out in the field?

Jaret Sprott: I would say no right now, Rob, because that’s a fairly small project, as we’ve stated before, RFS III, and we just really need the tower. So it’s not an extensive, it’s not 500 people on site, and it’s building a few pieces of equipment in some select fab shops. So you might see a little bit of cost pressure in there, but I don’t think that would be enough to deter us away from looking at that project. But since investor day, we have accelerated a handful of projects through gate one funding. So that’s small dollar amounts to get pre feed kicked off. And then we’ll be evaluating that here in the upcoming couple of quarters and making a decision on which projects go through gate two and ultimately gate three, and which ones won’t be.

Scott Burrows: Yes, I think, Rob, we’ll be able to understand kind of what current labor costs and what current costs are, which will help guide us in terms of which decision we make, which is, as Jaret pointed out previously, one of the advantages we have is we do have numerous sources that we can source the ethane from. And so any updated capital cost will go into that mix in our decision making.

Rob Hope: Thank you.

Operator: Thank you. The next question comes from Robert Catalier from CIBC Capital Markets. Please go ahead.

Robert Catalier : Hey you’ve answered most of my questions by this point, but I just wondered, given the massive development of the Peace system over the last several years, what’s your vision for developing it from here? What further optimizations are possible from this point?

Scott Burrows: So, Rob, I think there’s a few different things. And again, this question, given the breadth of the system, really depends on where the volumes show up. And so when you’re in Alberta, for the most part, we will focus on optimization. Now that we have segregated lines, and where can we use pump optimization, product optimization to increase throughput? We’ve already found some wins across the system to unlock some incremental volumes. We do have other areas where we can add low cost pumps, like from Fox Creek in, to increase volumes there. And then we’ll continue to look at opportunities in Northeast BC as LNG comes on. LNG Phase I and other opportunities come online and we see incremental growth there. So it’s a tough question to answer. There are certain areas that are tight where we’ll have to expand and there are certain areas where we have utilization opportunities.

Robert Catalier: Okay, understood. I’m just wondering what the thought is on frac spread hedging in light of both the current prices and your increased exposure now that you’ve consolidated Aux.

Scott Burrows: So Rob, we have a pretty programmatic hedging program based on where frac spreads are in terms of, from a statistical basis, P10 to P90 with very limited discretion as it relates to the hedging program. One of the benefits we did talk about on the original Aux Sable acquisition as well as with the new contract was it made it a lot simpler to hedge. As we stand today, we’re about 50% hedged in Canada and we actually have just under 50% of Aux Sable hedged for 2024 as well. Based on how frac spreads have trended, the forward curve, we’re somewhere in the neighborhood of 10% to 15% hedged for 2025 but we’ll likely be locking in incremental hedges given where forward frac spreads are compared to, I’ll call it the 5year to 10 year historical average.

Robert Catalier: Understood. Last question, just a clarification from Cam. I think, I understood from your previous discussion of taxes that the 24 current tax is not materially changed despite the increased marketing guidance. Is that correct?

Cameron Goldade: That’s correct, Robert.

Robert Catalier: Yes, thanks.

Operator: Thank you. The next question comes from Ben Pham at BMO. Please go ahead.

Ben Pham: Hi, thanks. Good morning. Can you guys talk about the M&A opportunities in Western Canada? Do you expect more of the Whitecap JV sort of structure? Do you think PE firms could be to monetize or even strategic looking to dispose of assets?

Scott Burrows: Hey, Ben. It’s a really hard thing to predict. We couldn’t have predicted that the Whitecap transaction was going to happen 6-7 months ago. I don’t know. We’re not seeing necessarily a lot right now and there’s still a fair number of producers that want to own that infrastructure. It’s very producer-specific, but we don’t have line of sight to a large M&A pipeline. Then as it relates to PE firms, again, I can’t really speculate. It still feels like a lot of the assets are relatively in their early fund life. We don’t see anything that’s being driven by fund life. I don’t have a good insight now as to what PE firms may or may not be doing.

Ben Pham: Okay. I understand. And I know there’s also some comments on Alliance Aux exceeding expectations and then the talking of Aux to maybe solidifying this energy a bit. Is that comment more suggesting that you might beat that 8 times multiple that you’ve commented about? Then what about that acceleration of the marketing volumes? Has that changed now?

Jaret Sprott: Ben, I guess I would just say that I think, obviously, as Scott mentioned earlier, we’ve been fortunate in the sense that the commodity complex has strengthened since we made the original acquisition and continues to show strength in this year and even out looking next year. In terms of the synergies, I think it does. Anytime you’ve got sort of full control of an asset, it obviously does put the wheel squarely in your hands to execute on those synergies. I think it does support us in that regard. I do believe that we will see additional opportunities as we get our arms wrapped around and sort of keep moving things forward as we’ve done with other assets. We at a point yet where we’re ready to put our hand in the fire and start to quantify those? Not yet, but I think we’re definitely seeing things evolve positively and so far, very pleased with the acquisition, the timing and the returns that it’s generating.

Ben Pham: Okay, thank you.

Operator: The next question comes from Robert Kwan at RBC Capital Markets. Please go ahead.

Robert Kwan: Thanks. Good morning. If I can start with guidance and just some of the thinking around the asymmetric increase. Is that just more of conservatism on the high end, whether it’s around some of the volumes that Jaret talked about earlier or maybe potentially anything you see on the rail side of things versus the low end coming up and just the confidence you’ve got with some of acquisition and the like?

Jaret Sprott: Yes, I think that’s a fair comment, Rob. As you suggest, there’s a number of things that go into it. I think we obviously had confidence to bring the low end up meaningfully from where it was last time, just based on such a strong first half. When we look at the second half of the year, there’s a couple of things obviously that are coming into effect, which some with certainty, some with less certainty. Obviously, as we look forward to the second half of 2024, we’ve got the quotient [ph] firm tolls are now under the revised tolling structure. While we continue to see strength at the moment, obviously when you look out in terms of interruptible flows through Q3 on Alliance, some uncertainty there could exceed our expectations, but obviously taking what we know at the moment.

Then lastly, clearly the big outstanding item or range is obviously the marketing book and how that shapes up. Obviously, some backwardation in the crude market here. The forward strip currently shows some strength in the gas market as we close out the year, but those are all uncertain. As we look at that, and then on top of it, as you point out a couple of things which are outside of our control, you’ve got a rail issue. We’re hopefully coming towards the tail end of wildfires in Alberta and Western Canada for the year, but that obviously always remains a risk through the summer here. So a few things on our mind that we bake in there. Obviously, we wanted to show strength by bringing up the bottom end and obviously bringing up the top end as well, but recognizing the uncertainty in the back end of the year.

Scott Burrows: The only thing I’d add, Rob, too, is just given we don’t control the closing of Whitecap, none of that transaction is in that outlook.

Robert Kwan: Got it. Thanks. If I can just turn to the RFS for costs and really just how do you think about the parallels, if any, or lack of parallels, I guess, with that versus what you’re seeing from Cedar? One thing just to touch on is I think Cedar had some off-site fabrication. Is that going to put pressure on that component at a minimum on the project?

Scott Burrows: None. None, Rob. Cedar, we had the lump sum at the time we press released, so that’s all reflected in the cost and all the fabrications being done overseas, not really anything in the fort. We see zero parallels between the two.

Robert Kwan: Okay, perfect. Then the last, just on the Whitecap deal, can you just talk about within PGI, you’ve got the return that makes sense for the joint venture. How do you think about the upside you can get from all of the other pieces? I don’t know if you want to quantify it, but just what are the different pieces that give you that upside? Specifically, can you just comment on the Muzro [ph] ethane angle under the Dow contract?

Scott Burrows: Good morning, Robert. Yes, so downstream, obviously, there’s the base acquisition of the K-Bob facility through PGI, and then there’s the capitalization of the Lator battery. That Whitecap will be executing that, and then we’ll be executing the pipeline to tie into Muzro. So, really, filling Whitespace through our K-3 facility as we connect that to the K-Bob facility down into the southeast, and then when you go west, maximizing the utilization of our original Cutbank complex, or Muzro complex as we call it, and then ultimately, we have the opportunity to take more gas through the deep cut at Muzro. So, obviously, that can be part of our overall diversification portfolio to satisfy a Dow contract. Then obviously, you have current liquids that are extracted at K-3 and the K-Bob facility, and then with incremental gas going through the K-Bob facility, obviously, there’s incremental contracts required through Peace and through the fractionator, and then ultimately through the back end of the frac like termiling and rail, etcetera.

Then when you shift over to Lator, all of the incremental condensate will flow on the Peace system. The incremental C-3 plus will be extracted from the gas, and the C-2 plus will obviously flow down the Peace system and all of those barrels. The condensate will be guided to various condensate outlets in Edmonton, and the NGLs will go through the RFS complex. So, that’s kind of in totality how the entire deal works. Base extensions on contracts and new incremental volumes through the value chain.

Robert Kwan: Got it. Thanks. That’s helpful. Could you see the magnitude of the stuff outside of then PGI approaching the magnitude in terms of contribution of the acquired assets?

Scott Burrows: Rob, sorry, I’m just not sure how to answer. Can you rephrase the question?

Robert Kwan: Yes, you’ve talked about, I don’t know, maybe we put it kind of in the build multiple or acquisition multiple context. Presumably what you did within the joint venture has to stand alone. So, how much more of a kicker are you going to get from all the stuff that you would get downstream?

Scott Burrows: Yes, I mean, that’s obviously would disclose confidential information that I just don’t think we can disclose at this stage. I mean, I think suffice to say Jaret tried to highlight the fact that in addition to the standalone PGI returns, we secured incremental utilization of our facilities through existing and expanded contracts. So, I think we’ve said what we needed to say on the actual acquisition release and then upon close, we’ll update 2025. But overall, we found the consolidated multiple in line with previous acquisitions, if not slightly better.

Robert Kwan: Okay, that’s great. Thank you.

Operator: Thank you. We have no further questions. I will turn the call back over to Scott Burrows for closing comments.

Scott Burrows: Well, thank you and especially thanks to the analysts who I know have had a busy two weeks and we’re at the tail end here. So, appreciate all the questions and the quality notes last night and to any of our employees or to all of our employees listening to the call, thanks for all the hard work. It was a really good quarter. Thanks, everyone. We’ll see you again in November. Thanks

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