Good morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation Q3 2024 Results Conference Call. This call is being recorded on Wednesday, November 6, 2024. I would now like to turn the conference over to Dan Tucunel, VP of Capital Markets. Please go ahead.

Thank you, Joanna. Good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the third quarter of 2024. On the call today, we have Scott Burrows, President and Chief Executive Officer; and Cameron Goldade, Senior Vice President and Chief Financial Officer; along with other members of Pembina's Senior Officer leadership team, including Jaret Sprott, Janet Loduca, Stu Taylor, Chris Scherman, and Eva Bishop. 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. 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 November 5, 2024, for the period ended September 30, 2024, as well as the press release Pembina issued yesterday. All of these materials are available online at pembina.com and on both SEDAR plus and EDGAR. I will now turn things over to Scott to make some opening remarks.

Thanks, Dan. We were pleased yesterday to report our third quarter results, highlighted by adjusted EBITDA of $1.019 billion and adjusted cash flow from operating activities of $724 million or $1.25 per share. Pembina is poised to deliver a record financial year, reflecting the positive impact of recent acquisitions, growing volumes in the Western Canadian Sedimentary Basin and a strong contribution from the marketing business. As Cam will discuss further in a moment, we have narrowed our 2024 adjusted EBITDA guidance range by $25 million on either end to $4.225 billion to $4.325 billion. In addition to solid financial results, the third quarter was highlighted by three notable transactions. The first was the acquisition of the remaining 14.6% interest in Aux Sable's U.S. operations, resulting in fully consolidated ownership of all the Aux Sable assets. This transaction allows further simplification of our corporate reporting and enhances our long-term service offering from the Aux Sable assets. In addition, PGI, jointly owned by Pembina and KKR, entered into two exciting transactions with growth-focused companies operating in the Montney and Duvernay. The first transaction with White Cap included the acquisition of a 50% interest in White Cap's Kaybob complex and an obligation to fund future Lator area infrastructure development. Further, the second transaction, PGI entered into agreements with Veren that included the acquisition of Veren's Gold Creek in-car area oil batteries and support for future infrastructure development. We are pleased to have closed this transaction effective October 9, 2024, and look forward to growing alongside Veren in the years to come. Under the agreement with Veren, PGI is committed to fund up to $300 million of future infrastructure, and we are pleased to be progressing in new battery and associated pipelines, representing more than half of the funding commitment. More details will be provided upon completion of upcoming engineering. Through these two transactions, we are realizing the vision set forth with the creation of PGI in 2022. We were successful with White Cap and Veren because we possess a unique ability to provide tailored and value-added solutions to support the specific needs of our customers. The opportunities arising from the creation of PGI have attractive economics and are expected to enhance asset utilization, enable future volume capture, and benefit the full value chain. We also continue to progress our various major projects. Portions of the Northeast BC midpoint pump station expansion have been completed, and we are on track to be fully complete by year-end. Notably, that project is trending under its $90 million budget. And while a smaller project, it is another example of Pembina's strong project execution. As well, we continue to advance further expansions to support volume growth in Northeast BC and are pleased that CR has turned their application for the Taylor to Gordondale expansion is complete, allowing us to proceed to the assessment phase. At our RFS IV expansion, site clearing activities have been completed, while engineering and procurement activity and site construction continue. Finally, regarding the Cedar LNG project, we reached an exciting early milestone with the start of onshore construction activities, including site clearing and other civil works. Detailed engineering is underway on the floating LNG facility, and we anticipate the start of construction in mid-2025. I'll now turn things to Cam to discuss in more detail the financial highlights for the third quarter.

Thanks, Scott. As Scott noted, Pembina reported record third quarter adjusted EBITDA of $1.019 billion, consistent with the same period in the prior year. While results were essentially flat period-over-period, we saw strong performance across most of Pembina's business primarily from the positive impacts of increased ownership of Alliance and Aux Sable, combined with growing volumes on certain systems and higher NGL margins. However, these results were offset by headwinds we faced on one specific asset, Cochin pipeline, and the combined impacts of various one-time and transitory events that impacted either the current quarter or the prior period. In pipelines, factors impacting the third quarter variance primarily included a higher contribution from Alliance due to increased ownership following the Alliance-Aux Sable acquisition, higher demand on seasonal contracts, and the reactivation of the Nipisi pipeline in late '23. These positive impacts were offset by a lower contribution from Cochin pipeline, primarily due to lower tolls on new long-term contracts, lower volumes resulting from a contracting gap from mid-July to August 1 associated with the return of line fill for certain customers, lower interruptible demand resulting from a narrower condensate price differential between Western Canada and the U.S. Gulf Coast, integrity spending, and lower net revenue on the Peace Pipeline system due to the earlier recognition of take-or-pay deferred revenue in the first half of 2024 compared to 2023, which more than offset higher contract volumes. In facilities, factors impacting the third quarter variance included the inclusion within facilities of adjusted EBITDA from Aux Sable following the Alliance-Aux Sable acquisition, partially offset by a gain on the recognition of a finance lease in the third quarter of the prior year. In Marketing and new ventures, the third quarter variance reflected the net impact of higher net revenue from contracts with customers due to increased interest in Aux Sable following the Alliance-Aux Sable acquisition and higher NGL margins. These positive impacts were offset by the impact of a 90-day unplanned outage at Aux Sable and lower realized gains on commodity-related derivatives. Finally, the third quarter corporate segment results reflect higher long-term incentive costs driven by Pembina's share price performance, partially offset by lower consulting costs. Earnings in the third quarter were $385 million. This represents an 11% increase over the same period in the prior year. In addition to the factors impacting adjusted EBITDA, earnings in the third quarter were impacted by unrealized losses recognized by PGI on interest rate derivative financial instruments due to falling interest rates compared to gains in the third quarter of the prior year, unrealized losses recognized by Cedar LNG on interest rate derivative financial instruments, unrealized gains on NGL-based derivatives and crude oil-based derivatives compared to unrealized losses in the third quarter of the prior year, larger unrealized losses on renewable power purchase agreements, a cost recovery related to a storage insurance settlement and higher depreciation and amortization expense and net finance costs. Pipeline volumes of 2.7 million barrels per day in the third quarter represent a 6% increase compared to the same period in the prior year. The increase was primarily due to the increased ownership interest in Alliance and the reactivation of the pipeline. These factors were partially offset by lower volumes on Cochin Pipeline, the Drayton Valley Pipeline, and the Peace Pipeline system. Lower volumes on the Peace Pipeline system were a result of earlier recognition of take-or-pay deferred revenue in the first half of 2024 compared to the first half of 2023, which more than offset higher contracted volumes. If you normalize conventional pipeline volumes for the earlier take-or-pay recognition and outages, volumes were up approximately 2% over the prior year. Facilities volumes of approximately 800 million barrels per day in the third quarter represent a 1% increase compared to the same period in the prior year. The increase was primarily due to the Alliance-Aux Sable acquisition, lower volumes at the Redwater complex, and lower volumes on certain PGI assets due to the earlier recognition of take-or-pay deferred revenue in the first half of 2024 compared to the prior year, which more than offset higher PGI interruptible volumes. Turning to our outlook for the full year, Pembina has narrowed its 2024 adjusted EBITDA guidance range to $4.225 billion to $4.325 billion. Further, we are currently trending towards the midpoint of the guidance range based on prevailing forward commodity prices and the outlook for fourth quarter volumes. Through the first three quarters of the year, conventional pipeline volumes have been modestly impacted by various Pembina and third-party outages and lower-than-expected interruptible volumes on certain systems, leading to slightly more moderated volume growth in 2024 than originally expected. However, the broader outlook for growth in the WCSB and Pembina's business remains strong, and the revised guidance is based on an expectation for the fourth quarter of higher interruptible volumes on certain systems and the impact of new contracts. At September 30, based on the trailing 12 months, the ratio of proportionally consolidated debt to adjusted EBITDA was 3.6x, which is at the low end of the 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 of the debt associated with the transaction that is currently only capturing two quarters of EBITDA contribution. On a normalized basis, this ratio would be approximately 3.4x. I'll now turn things back to Scott.

Thanks, Cam. The first three quarters of 2024 have been tremendously exciting, highlighted by acquisitions and major project announcements as well as the continued momentum from industry-wide growth catalysts including the Trans Mountain pipeline expansion, the near start-up of LNG Canada, new petrochemical facilities, and new or expanded LPG export capacity. As we work hard to close out the year strongly, our attention is also turned to 2025 and beyond and how Pembina can continue to capitalize on the opportunities arising from this growth and deliver long-term and sustainable value for our shareholders. Thank you for joining us this morning. Operator, please go ahead and open up the line for questions.

Your first question comes from Jeremy Tonet at JPMorgan.

I just want to start off with the conventional segment, if I could. I think you had mentioned 2% period-over-period growth there. I think in some of the market maybe we're expecting a little bit higher growth there. Just wondering if you could touch on a bit more dynamics as you see it there and the outlook into '25 and the potential for mid-single-digit growth, I guess, based on your producer customer conversations.

Yes, I'll let Cam clarify the 2% comment. As we look toward the end of the year, we anticipate a 4% growth rate on the conventional system. The third quarter was influenced by Pembina and third-party turnarounds. However, as we approach Q4, we expect third-party facilities to come online. Therefore, this 4% growth includes some contributions from those facilities. Looking ahead to 2025, we are still finalizing our budget and will update in December, but we remain optimistic about achieving a 4% to 6% growth rate in physical volume for that year. We're already noticing strong volumes in October compared to September. This growth is partly new and partly due to operations returning to normal. Cam, could you clarify your 2% comment?

Yes, sure. Jeremy. Just to clarify the 2% comment in my prepared remarks. If you sort of look at Q3 over Q3, the take-or-pay recognition and the outages collectively were worth a little under 60,000 barrels a day of impact there. So that gets you to the 2% when you normalize for that. Obviously, looking forward, Scott explained that well how we see that in excess of 2%.

Got it. Okay. So maybe some kind of turnaround noise in the quarter, but I guess, your longer-term outlook unchanged for mid-single-digit growth, if I got that correctly.

Correct.

And then maybe just pivoting over to Line now, having full ownership of the asset. If you could talk a bit more, I guess, as far as your outlook for what you can do there, how you can better optimize over time as legacy contracts roll? And could there be growth in the Bakken or otherwise? Just wondering what's possible at this point.

Jeremy, it’s Jaret here. Yes. So integration continues to go extremely well, not only with the Alliance asset but on the Apave asset as well. And then when we – looking at the synergies, those also were going as planned, kind of the shorter-term synergies. Longer term, what we’re hearing from our shippers and potential shippers is they continue to value the service offering. They very much like the high reliabilities at the asset, which provides to the shippers here in Western Canada and the Bakken. And demand for the asset remains extremely high. We are engaged, obviously, with our shippers, talking to them about how we can meet incremental demands, either full path or other opportunities, either out of the Bakken into the Chicago land area or maybe some interprovincial opportunities into Fort Saskatchewan or where demand for gas is required. So just kind of working through those right now, but very encouraged with the conversations and just really trying to understand where the shippers want their gas to go and how we can unlock that for them.

The next question comes from Praneeth Satish at Wells Fargo.

Maybe turning to Cedar. Given the agreement with the existing contract that you have with ARC there was secured prior to the start of construction and with construction at least partly underway now. I assume that the risk profile for Cedar has decreased. So should we think about future offtake contracts that you signed on Cedar carrying a higher rate to reflect that there's lower risk on the project now?

I think the interesting point is of an FID of Cedar, the interest in the project has increased, just given that it's real in people's eyes now versus prior to FID, I think people were waiting to see that decision. So I think between the FID decision as well as continued progress on the CGL expansion, people have more confidence in the project and the in-service date, the profile of that. And what that's led to is increased interest. And with that increased interest, we do believe that, coupled with the fact that this will be a scarce resource in terms of some of the only uncontracted LNG capacity off the West Coast of Canada that it should garner a premium. So that's certainly something that we're thinking about. We have term sheets out in front of potential off-takers, and we are in discussions. As we noted in the press release, we expect to continue into early 2025, but we are having good discussions.

Got it. And then on M&A, you've been active on the M&A front in recent quarters, especially at PGI but we've seen midstream valuations move higher over the past few months. Can you maybe help us understand how the bid-ask spread has evolved? Are you seeing actionable opportunities? Is that reasonable multiples that meet your return thresholds? Or is it getting harder to find accretive deals?

I think given the transactions we did in 2024, we’re focused right now on closing and integrating the acquisitions. We’re not out actively pursuing M&A opportunities. We’ll always look at something if it comes for sale; we don’t control the timing. So I’d say we’re in a reactive mode, not proactive mode. Just because we have enough on our plate to integrate and capture the value from the previous acquisitions.

The next question comes from Rob Hope at Scotiabank.

Just one question for me. Can you give us an update on the ethane opportunities as you move through the year? Are you increasingly clear in your definition of the next phase of opportunities?

Jaret here. You were trying to break it up, but I just want to repeat, you were talking about the update opportunities, I think, with respect to probably our Dow supply agreement. Unfortunately, it’s a little bit more of the same story. We continue just to evaluate the entire portfolio of our ethane supply. We have kicked off what we call internally at Gate 0 and Gate 1 funding to progress engineering pre-feed work and those types of things on various opportunities. And 2025 in the first half of 2025 is where we’ll sit down as a management team and really go for those opportunities and start to progress, which ones will go through Gate 2 and Gate 3. So you’ll see a little bit more, probably in the latter half of ‘25. And then the majority of that capital, obviously, in 2025 will be spent in the engineering and pre-feasible studies. ‘26, ‘27 when those assets come on stream is where you’ll see the majority of that capital being deployed to bring assets out of the ground.

The next question comes from Maurice Choy at RBC Capital Banks.

If I could just come back to CLNG, I think you mentioned that there has been increased interest from the offtaker perspective and an update might come instead in early 2025. Obviously, these are complex discussions and duties, but could you elaborate a little bit on how the discussions have generally evolved over recent months, be that in terms of the terms, the conditions, the volumes, or sort of in the competitive tension amongst the potential counterparties?

It's Stu. So our conversations continue to have been ongoing for the past year. We've regrouped and looked at, as Scott described, the opportunity, the derisking of the opportunity, and have picked up conversations with NOCs and IOCs who we were talking to previously. We've added additional counterparts in those conversations. Term sheets are out to those parties. At the same time, we've been conversing with Canadian producers about the opportunity of Cedar perhaps being an outlet for natural gas on a go-forward basis. So we've been pushing those conversations looking to get these term sheets out to people, both parties now have term sheets and those term sheets are reflective of similar terms that were in the ARC arrangement, but with some minor changes that have been warranted. And it's an iterative process, and we'll be pursuing more conversations in 2024, as described, and we'll be looking to close on those conversations in '25.

Got it. And if I could just switch over to a comment earlier about interruptible volumes on certain systems. I think the guidance includes some recovery of these volumes in Q4, and could you just elaborate a little bit more about these volumes and how sustainable these are beyond the quarter?

Exactly like what Scott was saying, seeing stronger physical volumes and revenue volumes into the fourth quarter. The IT barrel, we do outlook components of that. And it’s really around depending on which customer is really ramping up and how quickly they’re ramping up that brings an IT barrel, but we are anticipating, obviously, a bit of a rebound into the quarter in Q4 with respect to that segment.

The next question comes from Robert Catellier from CIBC.

Maybe I can start with a higher-level issue here. I'm curious what you think the PC election resultant changes at the Blueberry River First Nation mean for your growth plans in D.C.

This is Janet. With the NDP continuing to lead the government, we actually see a smooth transition. We've been working closely with the folks in the BC government with the Blueberry River First Nation and others. And we think this will be, again, just a smooth transition and the continued effort to implement the agreement between the two parties.

Okay. And maybe a question for Cam. I'm curious what you see as the sensitivity in your guidance to the work stoppage at the West Coast ports. How significant is that to your Q4 results?

Rob, it's fairly minimal. Right now, we had the work stoppage previously. I can't remember exactly when that was maybe last year. But it is somewhat immaterial to our Q4 outlook.

Okay. And then lastly, how are you seeing development change in the Duvernay given that there's been some recent turnover in some of the key lands there?

Once again, Jaret here. We see that recent transaction upon closing as being extremely positive. Obviously, the potential acquirer is a very prudent and technically savvy producer. The previous owner, we had a wonderful relationship with Chevron and continue to have so. But they were typically only allocating 1 to 1.5 rigs on a calendar year basis. And we’ve had some early conversations with Canadian Natural Resources just kind of outlining at a high level how the contract works. We’re really excited about their understanding of the reason for us and kind of get up and go to get after it and probably allocate more drilling rigs to the space. So we’re expecting to see some higher utilizations in the future. That’s for sure. We’re excited.

The next question comes from Ben Pham at BMO.

Just a couple of queries on the Cochin new contract. Can you comment on how the new toll compares to your original underwriting assumptions? And can you also talk about just maybe top-down key factors that were driving the renegotiations?

Yes. Sure. Ben, it's Jan here. I'll take the first part. So I think, obviously, when you look at the variance that we saw in Q3, sort of period-over-period, I mean there's a handful of things as we outlined in the disclosure that contributed to that. Obviously, the new toll framework, the revised firm holes, that is about a $20 million a quarter impact and is obviously the biggest single piece of the variance quarter-over-quarter. We talked about, obviously, this nuance in the contract where with the foundational shippers on the initial term having provided line fill, we were required to return the line fill to them and effectively, they shipped under that for that period in July. That was that along with the incremental integrity work for the quarter was about another sort of $12 million to $14 million impact. And we'd obviously characterize those as unusual or one-time events. And then lastly, the IT revenue portion in the quarter was affected by both the combination of the spreads, which are a consistent driver, but also we had a temporary outage of 110 associated with that asset, which put a natural limit on the ability to move in triple volumes. That really took up the balance of the variance. And so as we look forward to that asset, I think we're obviously happy to have it recontracted. I'll let Jaret speak on the dynamics of that exercise. But obviously, we see something that would exclude those one-time or extraneous events as we look forward.

Yes. Regarding the contract, our overall view of condensate demand in Western Canada is very positive, whether from the land area, the Gulf Coast, through Cochin Southern Lights, or the domestic supply from Western Canada. Considering these factors, when we acquired this asset, it had a throughput capability of about 90,000 barrels per day. Since then, our technical services teams have enhanced that capacity, and we can now consistently handle over 100,000 barrels per day. With the potential for additional capacity in times of strong spreads, the general outlook for demand is robust, particularly from our oil sands customers and buyers in Edmonton. We haven't discussed contract duration, but we can offer some discounts for longer-term agreements with specific counterparties. Taking all this into account, we are pleased with the contracts we've established and the partners involved. We currently have additional capacity, which allows us to approach the market for shorter-term sales. We believe that, in the long run, the spreads will enable us to keep the asset operating at full capacity daily. Overall, we are satisfied with our acquisition and the terms we've secured.

And sorry, just for a moment. I think on Cochin, one thing I should close out by saying is it's important to remember that when we acquired that asset originally, it was flowing about 85,000 to 90,000 BOE a day, and through the work that we've done, great work by the operations team, we've obviously increased the capacity of that asset, providing more egress and more access to condensate for our customers, obviously, creating more opportunities for Pembina. So we've grown that capacity meaningfully in terms of that size. Capacity is obviously well north of 100,000 barrels a day today, someday closer to 110,000 or 115,000. So that's obviously helped to support the underwriting thesis from the original acquisition.

Okay. I got it. So we should really look at not just obviously looking at quarter-over-quarter, but also look at the initial volumes. That's good. And then I will not comment on tenor, but once it's up for renewal again. And Cochin technically is it possible to be converted to an oil pipeline reverse, or that's not even in the cards at all longer term?

No, I think the demand for condensate imports and the supply for the oil sands will continue to be strong enough. But maybe one day, but it's not something we're looking at today.

Okay. I got you. And maybe just one cleanup, 1 in a piece, and there's reference to $15 million deferred revenues booked in the earlier period. Are you suggesting that under your prior accounting policies, the piece would have been up $15 million, 1-5, more than in the third quarter results? Or is there something else that was driven?

In previous years, due to having less data, we would have postponed recognizing those volumes until later in 2024. However, this time we recognized them earlier. As a result, if we were to compare apples to apples, you would have seen a $17 million benefit in Q3 of 2024 if it weren't for that timing change.

I got you. So there wasn't anything else notable outside of that impacting the piece?

Not more than what we said originally. So obviously, there was that piece. There were some outages that also affected this quarter. Those were the two biggest effects.

The next question comes from A.J. O'Donnell at CPH.

Just wondering if I could go to the marketing business for a second. I think results were pretty strong despite seeing an unplanned outage at the Aux Sable facility. I was just wondering if you could comment about your outlook for frac spreads going forward given where AECO prices are headed into the winter?

It's Chris Scherman. I think we expect a little bit more of the same here through the rest of the year on frac spread. Gas prices remain. Obviously, the challenge is we're still waiting on winter in most markets. And I think as we look through to '25. There's definitely some things we're watching, LNG Canada is coming on, or watching Ecogas. In that sense, we've got some incremental Gulf Coast frac capacity coming on with a lot of incremental egress. So we're watching that as well but remain fairly constructive in particular because of gas price.

Okay. Just one maybe on the Taylor to Gordondale project. Just curious if you could just give us a little bit more explanation on kind of what's going on there and what's needed during the assessment phase to kind of get that project moving along.

It's Janet. So in September, the CER issued its completeness determination. Essentially, what that does is it kicks off a 430-day review process. So we'll be in the midst of that, responding to information requests. We expect hearings to happen this summer and the decision from the CER later next year. Then I'll kick it over to the governor and counsel who will have 90 days to make a decision from there. So the process is underway, and we look forward to working with the CER and intervenors to answer their questions. There's obviously a high demand for this project. And so we expect the process to move forward.

And then just talking on the execution side. We continue to meet with landowners due to the engineering archaeology digs, all of our regulatory work, indigenous community capacity agreements, and working with our customers. So we continue to spend real dollars on the asset as well and starting to order some long lead equipment in anticipation for the approval to meet our customers on-stream on green dates. So things are going really well.

Next question comes from Anthony Linton at Jefferies.

If you look at the two infrastructure deals you did already this year, I think those were relatively well telegraphed by the respective producers. Just wondering if you're able to give us a sense of how your conversations with customers are progressing today and the potential opportunity set that you might see there moving forward.

Are you asking in relation to future M&A opportunities?

Yes, yes.

I mean, I would say our conversations with producers in general are positive in terms of volume growth. Again, based on some of the macro changes that we see from an egress perspective, I think people are relatively bullish, especially when you look at where the Canadian dollar is and the value of condensate, which drives a lot of value across our system. I think overall, just in general, the discussions are generally positive. Again, as it relates to M&A, we're very focused on integrating the assets that we acquired in 2024 and aren't in kind of active discussions on similar transactions, not to say that we won't be if opportunities arise, but that's not part of the conversation today. Most of the conversation today is generally around future volume growth and how we can meet those needs through gas plant, pipe, and frac.

Got it. Okay. No, that's helpful. And then maybe just one follow-on question. Just with those two transactions with Pembina taking more of, call it, a financial partner role than an operating role. Does it change how you think about the strategy on the facility side of the business? And I assume that's more driven by the producers than from Pembina. Is that the right way to think about it?

Jaret here. Yes, if you think about these two specific acquisitions that we just did with Baron & White Cap closed and awaiting closing. The operators, the upstream customers are going to really focus on their well-add to their oil batteries. And we’ll really focus on what we do well: processing natural gas, natural gas liquids, transporting those, and then obviously getting through the frac and getting their condensate into markets. So it’s not really a change at all. All of their liquids are going to flow onto a Pembina operated system and through the value chain. And all other gas is going to go through Pembina operated gas plants and gas facilities. So it doesn’t really change our philosophy at all. They’re really good at those types of things; so they should do that, and we’ll stick to what we’re really good at.

The next question comes from Manav Gupta at UBS.

Quick question. Any update that you have on the progress you're making at Redwater complex expansion and Rebate expansion?

Yes. So the Redwater IV expansion physically continues to go extremely well. I was just up there a couple of weeks ago. Things are coming out of the ground, so I’m excited to see that on the project execution side. With respect to the white space we have in recontracting, recall that RFS IV was essentially kicked off due to obviously high demand from our upstream customers. But it’s primarily due to three of the really big Montney dedications that we have in North D.C. That’s allowed us to get that project off the ground, and then we have a significant percentage of white space. That expert percentage of white space, we are – there is significant demand for it. So we’re just being very strategic. For example, the two acquisitions that we just talked about: White Cap and Veren, we were able to provide them incremental C3+ fractionation services due to the fact that we’re actively building a new C3+ facility. We have other contracts that we just haven’t been public about that we’ve executed. So it’s going extremely well. Demand is high. Obviously, Chris has talked about ACO is low. So our customers are trying to extract every barrel of NGL out of the that they can due to the strong frac spreads here in Western Canada. So all know, we’re extremely happy with the project. It’s going extremely well in execution and on the commercial side.

And the next question comes from Patrick Kenny at National Bank Financial.

Just back to Cedar LNG, and apologies if I missed it, but any thoughts or comments around this litigation challenging the patent infringement or if you see any risk to the construction schedule as this legal process plays out?

It's Janet again. As we have mentioned before, we are confident that the steelhead patent does not apply to the Cedar prior project, and we believe the patent itself is not valid. There is a current challenge that has been deemed invalid in Canada, and an appeal is set to be heard soon. Therefore, we do not expect any impacts on the construction or the in-service date for the project.

Okay. And then just maybe on the NGL marketing front. I was just curious how your team is managing this relatively warm start to Q4 across North America. I guess, with respect to sales volumes and how protected you might be on the hedging front relative to prior winters?

Yes. It’s Chris. A good portion of our NGL, proprietary NGL comes out of our frac spread business. And we’re about 50% hedged for the rest of the year on that and about 25% through the next year and about 25% through 2025. As far as strategy goes, we’ve got a fairly robust portfolio, but a good portion of it is pointed at the West Coast. And so we’re benefiting right now from that Far East pricing advantage, and we try to structure it such that we’re taking advantage of that wherever possible, especially in the kind of market we’re looking at right now. So NGL season and recontracting season are sort of upon us, but as we’re working through it, we’re definitely paying a lot of attention to list.

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

Well, thanks, everybody. We look forward to finishing the year strong. Thanks for your time. Thanks to our employees for all their efforts. Thanks to our shareholders for your continued support. Thanks, everyone.

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