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spk01: to Pembina Pipeline Corporation Q4 2023 Results Conference Call. At this time, online turn and listen only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press the star zero for the operator. This call is being recorded on Friday, February 23, 2024. I would now like to turn the conference over to Cameron Goldite, Chief Financial Officer of Pembina Pipeline. Please go ahead.
spk03: Thank you, Ludie. And good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the fourth quarter and full year of 2023. On the call today, we also have Scott Burroughs, President and Chief Executive Officer, along with other members of Pembina's leadership team, including Jared Sprout, Janet LaDuca, Stu Taylor, and Chris Sherman. 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 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 discussion and analysis dated February 22nd, 2024 for the period ended December 31st, 2023, as well as the press release Pembina issued yesterday, which are available online at Pembina.com and on both CIDAR and NCAR. I will now turn things over to Scott to make some opening remarks.
spk08: Thanks, Cam. We were pleased yesterday to report our fourth quarter results, which included quarterly earnings of $698 million and record quarterly adjusted EBITDA of just over $1 billion. We also delivered record annual adjusted EBITDA of $3.82 billion, which exceeded the high end of the original 2023 guidance range and reflects the strength, predictability, and resilience of Pembina's business. In 2023, we saw growing volumes across many systems, supplemented by the value enhancement from another strong year from Pembina's marketing business. Positive momentum in the Western Canadian sedimentary basin could be seen by more than 4% year over year increase in second half volumes in the conventional pipeline business. In 2023, Pembina progressed its strategy by sustaining and enhancing our business through various accomplishments we shared throughout the past year, including signing new contracts from the Peace Pipeline System, signing new and fore-extending existing contracts of the Redwater Complex, reactivating the Nipissie Pipeline, and approving new projects such as the 55,000 barrel per day RFS4 expansion, the expansion of the Northeast BC Pipeline and a cogeneration facility at BGI's K-BOP3 plant. In the fourth quarter, positive developments continued, including the announcement of a $3.1 billion acquisition of Enbridge's interest in Alliance and Oxable. Pembina's business is built around integrated, difficult to replicate assets that provide an enduring competitive advantage and unequal market access for customers. Alliance Pipeline and Oxable are world-class energy infrastructure assets and increasing our existing ownership of them will further enhance our growing franchise. We continue to expect the acquisition to close in the first half of 2024, subject to the satisfaction or waiver of customary closing conditions. On the commercial front, we announced yesterday that in support of Dow's Path to Zero project, Pembina has entered into long-term agreements to supply up to 50,000 barrels per day of ethane and for the associated transportation on the Alberta Ethane Gathering System. The Path to Zero project is an important development for WCSB representing a significant increase to the current ethane market in Alberta. Given Pembina's existing leading ethane supply and transportation business and integrated value chain, there are multiple opportunities for the company to benefit from this new development through both the existing asset base and new investment opportunities. During the fourth quarter, we also closed open seasons on the Cotion Pipeline for a total of 90,000 barrels per day and signed an incremental contract with an anchor customer for service on the Nipissie Pipeline, which is now contracted for more than half the capacity on a long-term basis with line of sight to the asset being fully contracted by the end of 2024. On the major project front, we continue to progress our Phase 8 piece pipeline expansion and our RFS-4 expansion of the Redwater Complex. On the Phase 8 project, the capital budget has been further revised lower to $430 million, which is a hundred million dollars under the original budget. The construction is expected to be completed in the first quarter of 2024 with pipeline and facility commissioning and startup expected in the second quarter of 2024. Our experience of Phase 8 is another example of supporting Pemina's track record of strong project execution. Additionally, Pemina gas infrastructure has provided, has approved an expansion at the Wapiti plant that will increase natural gas processing capacity by 115 million cubic feet per day and is expected to be in service in the first half of 2026. The Wapiti expansion is being driven by strong customer demand, supported by growing montany production and will be fully underpinned by long-term take or pay contracts. Finally, yesterday, we provided an update on the Cedar LNG project. Cedar LNG has substantially completed several key project deliverables, including obtaining material regulatory approvals, advancing inter-project agreements with Coastal Gosling and LNG Canada, signing a heads of agreement with Samsung Heavy Industries in Blackham Beach, and executing a lump sum engineering procurement and construction agreement to provide Cedar LNG with the necessary services to construct the project. While a lot has been accomplished, there remain a number of schedule driven interconnected elements that require resolution prior to making the final investment decision. These include binding commercial offtake, obtaining third party consent and project financing. On this basis, a final investment decision is now expected in the middle of 2024. I will now turn things over to Cam to discuss in more detail financial highlights for the 2023 fourth quarter and full year.
spk03: Thanks Scott. As Scott noted, Pemeter recorded fourth quarter adjusted EBITDA of $1.03 billion. This represents a 12% increase over the same period in the prior year. In pipelines, factors impacting the quarter primarily included higher volumes on the Peace Pipeline system, Drayton Valley Pipeline and on the recently reactivated Nipissie Pipeline, higher holes primarily on the Cochin Pipeline and Peace Pipeline systems, largely related to contractual inflation adjustments and lower contributions in the Alliance Pipeline, primarily due to lower interruptible holes and volumes. In facilities, factors impacting the quarter included higher contribution from the PGI assets, primarily from the former Energy Transfer Canada plants, the Heist plant and the Dawson assets due to higher volumes and higher revenue at Vancouver Works. In marketing and new ventures, fourth quarter results reflect the net impact of higher contribution from OXABLE, lower natural gas and crude oil marketing margins, largely offset by higher NGL margins and realized losses on commodity-related derivatives in the fourth quarter of 2023 compared to realized gains in the fourth quarter of 2022. Finally, in the corporate segment, fourth quarter results were largely consistent with the same period in the prior year. Earnings in the fourth quarter were $698 million. This represents a 187% increase over the same period in the prior year. In addition to the factors impacting adjusted EBITDA, the increase in earnings in the fourth quarter was primarily due to the net impact of the impairment reversal related to the Nipissie Pipeline, the Ruby settlement provision and associated legal fees incurred in the fourth quarter of 2022, lower project write-offs, higher depreciation and unrealized gain on commodity-related derivatives compared to a loss in the fourth quarter of 2022, lower net finance costs and higher income tax expense and the recognition of a previously unrecognized deferred tax asset. Total volumes were 3.45 million barrels per day in the fourth quarter. This represents an increase of 2% over the same period in the prior year, reflecting the net impact of the reactivation of the Nipissie Pipeline, higher volumes on the Peace and Drain Valley Pipelines, higher volumes from PGI and lower volumes at the Redwater Complex. The fourth quarter contributed to foliar results that included earnings of $1.776 billion, record adjusted EBITDA of $3.824 billion, which was 2% higher than in 2022 and exceeded the high end of the company's original guidance range. Cash flow from operating activities of $2.635 billion and adjusted cash flow from operating activities of $2.646 billion. Thanks to strong results, Pemina generated meaningful free cash flow, which was allocated to strengthening the balance sheet and returning capital to shareholders. In 2023, we raised the common share dividend by 2.3%, repurchased $15 million common shares and continued to reduce leverage below the low end of the target range. At December 31st, 2023, based on the trailing 12 months, the ratio of proportionally consolidated debt to adjusted EBITDA was 3.3 times reflective of our strong balance sheet and supporting a strong BBB credit rating. I'll now turn things back to Scott.
spk08: Thanks Cam. In closing, we are enthusiastic about the future given the current momentum in the WCSB and expected continued volume growth through 2024 and beyond. Our broader outlook remains unchanged as we see the potential for mid single growth driven by tangible near term catalysts, including up to approximately $2.8 billion or 2.8 billion cubic feet per day of new natural gas export capacity from the new West Coast LNG projects, 590,000 barrels per day of new crude oil export capacity from the expected completion of the trans mountain pipeline expansion and potential new developments in the Alberta petrochemical industry, including significant incremental ethane demand associated with Dow's path to zero project. Given the scope and reach of our business, Pemina is uniquely positioned to benefit from these catalysts. Our investors have come to expect strong and consistent financial leadership from us demonstrated by a secure and growing dividend and unwavering commitment to our financial guardrails, a low risk and primarily fee-based business with high taker pay or cost service contributions and a strong balance sheet. You can expect us to continue to execute our strategy with the same financial discipline that has made us successful to date. In closing, I believe the next five years will be an exciting time in the Canadian energy industry with exceptional resources, greater access to global markets and leading environmental and social performance standards. Canada's energy industry has an opportunity for greatness. I'm extremely proud of what Pemina and the rest of our industry do to ensure responsibly produced energy is available to meet growing global demand. Thank you for joining us this morning. Operator, please go ahead and open up the line for questions.
spk01: Thank you. And ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the number one on your telephone keypad. You will hear a three tone prompt acknowledging your request and your questions will be pulled in the order that you received. Should you wish to decline from the polling process, please press the star followed by the number two. And if you're using a speaker phone, please keep the hands up before pressing any keys. One moment please for your first question. And your first question comes from the line of Jeremy from JP Morgan. Your line is open.
spk05: Hi, good morning.
spk08: Morning, Jeremy.
spk05: Just wanted to go into the Dow announcement a little bit more as far as this ethane supply agreements concerned and wondering if you could frame up, I guess, is this all incremental ethane extraction kind of upside new to the system? Is there any redirection? And also how much of this would you characterize as brownfield versus greenfield investments here? Just trying to get a sense for what the project economics could look like here.
spk12: Good morning, Jeremy, Jeremy here. Yeah, great question. So super excited to obviously announce our, our contribution to Dow's net zero cracker here in Alberta. With respect to our supply, it is going to be a material increase to Pemina's overall supply. It will require us to, to spend incremental capital with respect to getting that supply. You know, we've spoken previously about RFS three that was originally designed as a C three plus fractionator, but it has the optionality for us to put DF on it. So that would be a brownfield expansion. There are other opportunities at Empress and through PGI and or Pemina wholly owned extraction assets that we see opportunities. We also obviously see a massive, you know, positive with respect to utilization across our asset base and with 50,000 barrels of ethane, obviously a bunch of C three plus comes along with that. So it is going to be a mix of brownfield and greenfield opportunities for Pemina and higher utilization across the board. And then on the eggs pipeline, Pemina has announced that we're going to be 50,000 barrels. We fully expect that we're not the only contributor to, to Dallas supply portfolio. We don't know where the other portions of that supply portfolio are coming from. So once we understand where that's coming from, we'll be at be in a better position to update the all on, on eggs expansions.
spk05: Got it. That's a very helpful there. Is there any way to frame what the potential capital deployment sizing or timeframe or sizing really could be for this?
spk08: Yeah, Jeremy, it's Scott here. We've been progressing, as Jared pointed out multiple options. You know, we're we're working the engineering and the and the economics of all of those. So I would say, you know, probably by mid year we'll be in a better position to update the market and kind of which projects we predict will be going forward. But suffice to say no material capex in 2024.
spk05: Got it. Understood. And just one last one, if I could, pipe and reactivation here. Just wondering if you could speak a bit more on the market drivers to this in, I guess, you know, commercial momentum here, or what you see in the market is their potential to, you know, could this be, you know, fully filled up? What type of timeframe, you know, could that, materialize over and what are the drivers here?
spk12: I'll take that again, Jeremy. So the drivers are the clear water formation. So, you know, a lot of activity in that neighborhood. And we expect the pipeline to honestly be, you know, fully, fully contracted by the end of 2024. We put it back into service last year. We're seeing very strong utilization, physical utilization today. We've signed up incremental contracts, which I believe we announced at the end of last year. And, yeah, fully see line of sight to having that 100 percent contracted by year end.
spk05: Got it. That's helpful. I'll leave it there.
spk01: Thanks. Thank you. And your next question comes from the line of Rob Hope from Scotiabank. Your line is open.
spk12: Good morning, everyone. I want to stick on the Dow announcement and the supply district in West
spk02: group.
spk12: When you look at the options, you know, do you expect that the incremental ethane supply sources will all be Western Canadian? Or could you be pushing some incremental barrels on Vantage? I just want to get a sense of whether or not you're expecting this all to be Western Canada or some of the pockets.
spk08: Yeah, Rob, like, you know, again, this is this this ethane is going to be supplied from a mix of the existing portfolio as well as new. And and the new the new the new ethane will come from some of the various projects that we're currently evaluating. We discussed there definitely is an option to move incremental barrels on Vantage out of the Balkans. That is a very real possibility to supply. I appreciate that.
spk12: And then maybe just moving over to kind of the volume outlook for 2024, you know, a number of moving parts, including, you know, we'll call it rather strong, condi pricing, offset by weak, eco pricing. When you're talking to your producer customers, how do you think volumes progress through the year? We can see a little bit of softness in the front part and then ramping up into, you know, LNG Canada in 2025.
spk08: Yeah, you know, Rob, I think we continue to believe in that mid single digit growth that we talked about, but we are monitoring producer CAFEX budgets pretty closely and have ongoing discussions. And so certainly it's on the back. You know, it's on top of mind in terms of what producers are going to do throughout the rest of this year. But but to your point, you know, obviously we'd like to be a little bit higher for our producing community. But with oil at seventy seven dollars, condensate premium and Canadian dollar earning over one hundred dollars for your condensate carries the day a lot a lot of the time. And so we still believe that our producers economics are very robust, just given where condensate pricing is. But we are certainly watching producer budgets given the weakness in a go.
spk03: I would just add to that, Rob, on top of the liquids market, the condensate market, you know, obviously the market has bounced around a little bit, but certainly December, January and into February here, you know, we've seen some strength there. And obviously, you know, the the Arb into the Far East markets continues to be open and supportive for that as well. So, you know, we do see that that buffering the weaker gas prices as well.
spk00: Thank
spk03: you.
spk01: And your next question comes from the line of Linda is her from your line is open.
spk07: Thank you. Recognizing we'll likely get an update on Cedar energy mid year. Just wondering how we might think about the bookends of cost estimates for the project, recognizing that. A few things have moved around, including foreign exchange, since you first announced the project.
spk03: Yeah, thanks, when it can here, you know, I guess we'll continue to defer being very specific about that question until we we can really tell the whole story around the opportunity. I mean, obviously, you know, when we when we bought into that project, you know, we announced the capital cost of of in the mid mid two billion range US dollars. You know, obviously, the world has changed since then, and I think we all recognize that it's going to be higher than that. That said, you know, when we look at Cedar from a global competitiveness standpoint, you know, we see that it continues to stack up very well from a cost per ton basis. Against the, you know, the North American alternatives into the global markets, reflecting, you know, both the capital intensity, but also, you know, the West Coast advantages in terms of shipping that that Cedar enjoys. So, you know, recognizing that there's a desire for more more specificity, we'll probably leave it at that until we can tell the full story.
spk07: Okay, and maybe as a follow up, if you can help us understand. Given all of what you just shared in terms of that that compelling advantage has anything changed about your return expectations for the project. Would you expect kind of similar returns, even with a higher capital cost or potentially higher given the compelling locational advantages or maybe where your initial returns higher and they've come down a bit. Is there anything that you can point towards directionally?
spk03: Yeah, I would say from where we look at this project, you know, from this point in the development cycle, the economics of Cedar continue to reflect what we would have seen historically in terms of green field type returns, you know, for projects of this sort. You know, they're clearly not where, you know, the brownfield opportunities are. And obviously, we've got a number of those as well. But, you know, they would continue to be in that in that same sort of historical range, you know, that that mid to high single digit kind of range.
spk07: Thank you. And just maybe commercially as well, recognizing that there's a few moving parts. Can you talk about what the potential sticking points are about getting to firm off take agreements and what sort of mix of, you know, take or pay versus fee for service or other attributes would you be looking for in any off take agreements?
spk08: Linda, it's Scott here. You know, I think really it's time. You know, there's just a lot of different agreements that have to be put in place. And so we're continuing to progress detailed negotiations. But a lot of it is just is just due to time and the interdependency of so many different agreements on this project. In terms of, you know, our structure, recall that that that this project will be project financed. And so just by the nature of that, this project will need to have significant underpinning in order to proceed on that basis.
spk07: Thank you.
spk06: Thank you. And your next question
spk01: comes from the line up Robert from capital markets. Your line is open.
spk04: Hey, good morning. I'm going to follow up here on the, the supply agreement. I'm wondering if you could explain the exposure that you have on that agreement to commodity prices and volumes.
spk03: Yeah, Robin, you know, I think, you know, that if you think about the way that I think is contracted in Western Canada, it's obviously different than than other parts of North America. And so generally speaking, you know, the way that works is that, you know, it's ultimately for folks like us, a fee based structure. But, you know, the way that that that Pemina really makes money is on this is through transportation and and provision of of the volumes through the rest of the asset base. So, you know, as we sit today, through the conventional business, through the transmission business, through the, you know, the deep cuts and the gas plants and the fractionators, it's really sort of the tolling model that is the value driver for the ethane molecule, along with the associated C3H4. The C3 plus that comes with those molecules when you extract it.
spk04: Right. So to the extent the market's short or tight and the, you know, maybe maybe short volumes or the price is up. But that ultimately is borne by the counterparty.
spk03: That's correct.
spk04: Right. And then, you know, I wondered if you could just talk a little bit about the degree of additional costs for some of the emerging regulations and amended methane regulation, for example, clean fuel regulation, etc, etc. You know, typically we would expect any change of law or tightening of these regulations to have some cost sharing with your customers. But, you know, as it seems like a pretty, you know, I guess, a continually evolving landscape as far as environmental regulation goes. But as you look over the horizon, the next three to five years, is there any substantial change to your cost structure that's not otherwise shared with with shippers or producers?
spk08: Not at this stage, Rob. I mean, I think we're continuing to assess, you know, all the existing and pending regulations. We continue to work on decarbonization of all the assets and really understanding, you know, where we can get, you know, the best emission reductions for the best dollar value. As it relates to contracting, as you pointed out, many of the assets have cost sharing arrangements, which protects us a little bit. But we also have assets like Empress where we're fully exposed and we're working on, you know, what the implications are that. But at this stage, there's no what I'd call material change in the cost structure.
spk04: Okay. Last question for me is just, you know, are there any significant implications for Chevron selling their Duvernay assets in terms of your business
spk12: development? No, no major implications, Rob. Actually, we're excited. We're going to support Chevron through the transaction. You know, Chevron, I would say, has taken a modest approach to the development in the area. And we believe that, you know, upon divestment of those assets, the acquirer may take a more advanced or aggressive approach on developing those resources, which will benefit PGI and the rest of Pemina's infrastructure.
spk08: Yeah, Rob, if you look back at, you know, say over the last 18 months, there's been, you know, a fair bit of M&A activity in Canada on the asset side. And I think what we've seen historically has been new acquirers tend to deploy more capital than previous owners, you know, whether that's to make their transactions go around, or that's obviously what they believe in at the time of the transaction. And so we have found M&A over the last 18 months to actually be an acceleration. And you've seen that in the increased utilization across the PGI asset. So, you know, Chevron is a great counterparty. But we would expect, you know, potentially higher volumes over the, you know, over the relatively near future through an acquisition of a third party.
spk04: Okay, thank you. And congratulations on all your business momentum. Thank
spk01: you. And your next question comes from the line up. Praneet Satish from Wells Fargo. Your line is open.
spk13: Thanks. I guess two more questions here on the Dow agreement. So the supply agreement of 50,000 barrels, as you mentioned, I mean, that's not the full ethane supply. I think it's only about half of the crackers needs. And I guess I'm just struggling to think about who could satisfy the balance of the ethane, just given your position. But I guess even if there's another 50,000 barrels of ethane coming from other plants in the region, can you still pick up a benefit by moving some of that third party supply through your pipelines?
spk08: Yeah, you know, again, we don't have line of sight to where the rest of the ethane is coming from and in what phase and what timeline. So, you know, potentially a question for others. But depending on where that ethane comes from, we would have an opportunity to move in on our pipelines. You know, again, we have the only C2 plus pipeline in operations today gathering lines. And so when we have a pretty big frac footprint. So there is the potential. But at this stage, we, you know, we're not aware of where the next or where the rest of the ethane is coming from.
spk13: Got it. And then kind of second question on this project. I mean, you talked about the potential to produce more propane and butane from increasing the NGL cut on your plants for the project. I guess, how are you thinking about the end markets for this incremental supply of C3 plus? Is there maybe enough to consider an LPG export dock expansion or will it get railed into the US?
spk11: It's Chris here. Yeah, you know, we certainly are tracking that closely and recognize that with the ethane will come more propane and butane. It's likely that it's going to find a path to the West Coast. So we're back, you know, revisiting what we can do at our facility. We're looking at what others are doing and watching that closely. And I think it will inevitably spur something on the West Coast.
spk02: Got it. Thank you.
spk06: And your next question comes from
spk01: the line up Robert Klein from RBC Capital Markets. Your line is open.
spk09: Good morning. I can start with the topic of the day with Dow. So you talked about the potential to put a DF on the front of RFS3. What other capital should you see going into the system, whether it's compression or deep cuts out in the field and just under the agreement then with Dow, given you're still working through the cost of everything. Does the agreement specify return on the capital or are you taking the risk on how all of this capital needs to come together within whatever fee you've agreed with Dow?
spk08: Yeah, Robert, you know, I have to be careful what I say because we have obviously confidential arrangements, but we are obligated, it is a supply arrangement, so we're obligated to provide the ethane. You know, we are again going back to the initial comments. We have a mix here where a significant portion will come from, you know, existing assets or very light capital touch to existing assets. And then in terms of the new supply, we do have a mix. And so, you know, you pointed out potentially, you know, as an example, incremental deep cuts, RFS3, DF. There's other opportunities that we just can't talk about at this stage that we're exploring. And so for us, it'll be about how to get the most ethane for the least amount of cost. And that's something that we're currently assessing right now. And I know there's a lot of questions on it, but we're just not at the stage where we can provide that detail. And we'll look to do that, you know, once we make some of these decisions on a go forward basis. But it will be an overall mix of existing assets, light touch brownfield, and then some incremental greenfield investment.
spk09: Got it. And Scott, can I just square your comments here though up with an answer earlier that if the market is caught short, and there is a need to go out and attract ethane supply at a high price. I know that most of ethane is cost of service in the province. But if you have to do that, there was the statement that that is going to be borne by Dow. So how does that square up just in terms of your obligations to supply?
spk03: Yeah, sorry, Rob, I'll clarify my comments. What I meant was that the cost, the pass through to ultimately the producer who is providing the ethane, you know, there's an arrangement there. But it's a supply agreement and we have the obligation to supply. So we have the capital cost element to that. But there's the prices is fixed.
spk09: Okay, if I could just shift to Cedar, you listed a number of things that you got to work through one of them that you didn't list those just around costs. So, you know, coming out of the feed study, you comfortable with where those costs are, how you're going to manage the risk and it really is now how do you deal with the commercial on the other side, I guess, specifically on costs. Can you just talk about how you are planning on managing, you know, cost overrun risk and specifically, you know, you've talked about fixed price VPCs, but how are you planning on protecting yourself against the material type of overruns that we've seen in other projects that have led to contractor bankruptcies?
spk08: Yeah, Rob, I'll start there and Stu, feel free to jump in. But again, part of the timing around this project was ensuring that we had a very robust EPC contract lump sum turnkey. Again, this is a ship being built in Korea in Samsung shipyard under a controlled environment with LNG modules being placed on top of it. And that is all under a lump sum turnkey arrangement, which is, you know, the vast majority of the cost, which, again, we'll lay this all out, you know, if you are fortunate enough to make an FID decision. So I'm not trying to be coy, there's just a lot of moving pieces. But on that piece, you know, we feel very, very comfortable given the robustness of the contract that we negotiated that the vast majority of that price has been pushed off onto our EPC contract. The remaining price that's on risk for Pemina is pipeline and transmission lines. And, you know, it's a nine kilometer pipeline, 10 kilometer pipeline. You know, I think given our track record, I would hope the market has some confidence around our ability to deliver on that. I mean, you just saw phase eight come in materially under budget. So we feel confident around doing our core business on on this asset. And then, of course, on top of that, we have, you know, typical project contingency and and and protection. So overall, we feel good mainly because of, you know, we went with a lump sum engineering contract and those always cost a little bit more. But from a risk reward basis, we like that approach to major projects.
spk09: Totally. It sounds like I just need a quick one here just on the Alliance OXAble deal. You've got AHSR, but can you just comment on where you are on the Canadian Competition Bureau approval?
spk03: Yeah, Rob, I would say that, you know, timing wise, you know, you can see that we reiterated our second half, our first half of 2024 timeframe. You're correct. We've got the waiting period expiry on HSR and Transport Canada. I would say we don't have any better information at this point on the Competition Bureau process to to refine that view anymore. Things are progressing as expected as planned, but but no sort of further visibility at this point to try and narrow that date. Okay, thank you.
spk06: Thank you. And your next question comes
spk01: from the line of Zach Van Everen from TPH. Your line is open.
spk10: Hey guys, thanks for taking the question. Just going to the Fort Sass Frac markets, it seems like a lot of those facilities are running close to full. I was just curious if you guys had any incremental room to capture if spot rates moved up and then as you talk to producers, are Frac constraints becoming more and more of a concern?
spk12: Yeah, good morning, Jared here. The answer to your question is, is yes, but we it is becoming a concern for our customers. But it's also we don't have a lot of opportunity, unfortunately, because we're fully contracted for the most part. We don't have a lot of opportunity to get a lot of spot rates. The NGL season does start on April 1st. So the teams are are obviously in deep negotiations with respect to annual deals, but the majority of our customers are in the market. And the majority of our contracts at our Fractionation Complex are long term in nature, you know, five, 10 plus years. So unfortunately, where we can grab those opportunities, we do, but it is
spk08: long term in nature. But certainly Frac future Frac negotiations continue to progress and with RFS being the next Frac in service, RFS4 being the next Frac in service, you know, we have the option, we have the option to continue to progress those negotiations and sign up incremental barrels. That's predicted to come online in the first half of 2026 and is really the next, you know, material Frac expansion that we're aware of. And so those discussions continue.
spk10: Okay, perfect. That's super helpful. And then one on coaching. It seems like, you know, coaching and competing fights over subscribe ship or interest. I was curious if you could squeeze any more capacity out of that system with, you know, smaller capital efficient solutions or maybe there's a bigger project you guys could do as well.
spk12: I'll take that again. So, coaching since we've acquired that asset in December of 2019, we've increased the throughput by roughly -30% and safely. So I would say that we're meeting all of customer demand today. Our availability is extremely high. But I don't think there's without a major expansion, there's not a lot of room, unfortunately, left on that asset.
spk10: Okay, perfect. Super helpful as well. That's all I had for today. Thanks, guys.
spk01: Thank you. And your next question comes from the line of Patrick Kenny from National Bank Financial, your line is open.
spk02: Yeah, good morning, guys. Just on the WAPID expansion. Nice to see the commercial support there. Wondering if you could just update us on what other GMP expansion opportunities might be in the queue across your portfolio, you know, based on the customer activity levels that you're seeing in the field these days.
spk12: I can't speak to specifics, Pat. But I think a couple of quarters ago, I mentioned that we had line of sight to a substantial amount of capital to be deployed on a gross and a net basis through PGI. But obviously, with the K3 cogen, which is going to, you know, obviously increase the reliability of that asset, lower the carbon intensity, the WAPID expansion, that'll utilize the acid gas transmission line that we acquired this year. Through the Energy Transfer Canada acquisition, we have other opportunities to do, I would call it what field based processing, but incrementally through PGI with the partnership with Dow and our incremental C2 supply agreement, we have opportunities to deploy more capital on the field based extraction as well. So can't get into the specifics, but lots of opportunities for sure.
spk02: And then maybe from a tuck in or M&A perspective, curious, Jared, you know, if you're seeing any shift in producer appetite for third party gas processing services, just given, you know, the outlook for gas prices, at least through the summer, and, you know, maybe their need to secure downstream access and maximize the value of their liquids production within their overall netbacks.
spk08: Yeah, I would say no material change in the market there continues to be, it's very producer specific in terms of, you know, certain producers want to own and operate and that's core to their business and others, you know, look at, at, you know, what opportunities there are for mid streamers to to enhance their capital allocation decisions. And so I would say it's both discussions are ongoing and always have been and it's really, really producer specific, but I wouldn't say there's any kind of material step change given gas prices or anything like that. It would be normal course. I would say though, Pat, that any acquisitions
spk12: we do through PGI, obviously we have to be on side with our partner, but we really want to make sure that we're focused on the geology that we're buying processing assets that, you know, have long reserve life indexes and then obviously contribute to the rest of Pemina's value chain.
spk02: Okay, that's great. Thanks, guys. Thanks, Pat.
spk01: Thank you. And ladies and gentlemen, we have reached the end of our Q&A session. I would like to send it back to Pemina's president and chief executive officer Scott Rose for closing remarks.
spk08: Well, thank you, everyone. Thanks to our staff that are listening in to our customers. You know, we really appreciate all the hard work and thank you to all the investors and analysts on the call. 2023 was an exceptional year for our company and we're pretty excited about what we can deliver in 2024. So thank you, everyone.
spk01: Thank you, presenters and ladies and gentlemen, this concludes today's conference call. Thank you for participating in me now.
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