Pembina Pipeline Corp
TSX:PPL
Earnings Call Analysis
Q4-2023 Analysis
Pembina Pipeline Corp
The company is poised for growth, leveraging opportunities such as a burgeoning Canadian energy sector forecasted to undergo significant development by the end of 2024, including new West Coast LNG projects and the anticipated completion of the TransMountain pipeline expansion. This strategic positioning is expected to result in mid-single-digit growth, although they are keeping a close eye on producer's capital expenditure plans which could impact future growth trajectories.
On the project economics front, investing in Pembina reflects a balanced approach of both brownfield and greenfield opportunities. The anticipated capital expenditures are not material for 2024, suggesting a cautious and measured expansion pace. This conservative financial approach embodies their commitment to providing value while maintaining a strong balance sheet.
The company's management of capital projects showcases their historical consistency in delivering on budget. With most of the price risk offloaded onto the Engineering, Procurement, and Construction (EPC) contracts and a solid record of accomplishing under-budget projects, they are confident in their executional capacity and risk mitigation for impending projects.
A sign of stable financial health for Pembina is its fee-based business model, which mitigates volatility and provides consistent revenue streams. The contracts at their fractionation complex predominantly span long durations of 5 to 10 years or more, demonstrating the company's potential for sustained income and opportunities to engage in future negotiations for incremental revenue growth.
Pembina maintains ample scope to deploy capital, particularly through field-based processing initiatives and partnerships, such as the one with Dow for incremental C2 supply agreement. These reflect targeted investments aimed at enhancing the reliability and reducing the carbon intensity of their assets, indicative of a commitment to sustainability and operational efficiency.
Despite fluctuations in market conditions and commodity prices, Pembina has not observed any substantial change in the market. With a producer-specific approach to operations, the company recognizes that certain producers prefer ownership and operation as a core part of their business. This awareness allows Pembina to tailor its services and offerings strategically.
Looking forward, the company is maintaining its current project timelines, with significant milestones expected to be reached in the second half to the first half of 2024. However, uncertain elements such as the Competition Bureau process still require clarification before they can offer more precise forecasts.
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Good morning, ladies and gentlemen, and welcome to Pembina Pipeline Corporation Q4 2023 Results Conference Call. [Operator Instructions] This call is being recorded on Friday, February 23, 2024.I would now like to turn the conference over to Cameron Goldade, Chief Financial Officer of Pembina Pipeline. Please go ahead.
Thank you, Goldie, 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 Burrows, President and Chief Executive 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 made, expressed or implied 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 22, 2024, for the period ended December 31, 2023, as well as the press release Pembina issued yesterday, which are available online at pembina.com and on both SEDAR and EDGAR.I'll now turn things over to Scott to make some opening remarks.
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. The 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 or extending existing contracts of the Redwater Complex; reactivating the Nipisi Pipeline; and approving new projects such as the 55,000 barrel per day RFS IV expansion; the expansion of the Northeast BC pipeline; and a cogeneration facility at PGI's Kaybob 3 Plant.In the fourth quarter, positive developments continued, including the announcement of a $3.1 billion acquisition of Enbridge's interest in Alliance/Aux Sable.Pembina's business is built around integrated difficult-to-replicate assets that provide an enduring competitive advantage and unequalled market access for customers. Alliance Pipeline and Aux Sable are world-class energy infrastructure assets and increasing our existing ownership with 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 Path2Zero 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 Path2Zero project is an important development for the 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 Cochin pipeline for a total of 90,000 barrels per day and signed an incremental contract with an anchor customer for service on the Nipisi 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 continued to progress our Phase VIII Peace Pipeline Expansion and our RFS IV expansion of the Redwater Complex. On the Phase VIII project, the capital budget has been further revised lower to $430 million, which is $100 million under the original budget. The construction is expected to be completed in the first quarter of 2024 with pipeline and facility commissioning and start-up expected in the second quarter of 2024. Our experience with Phase VIII is another example of supporting Pembina's track record of strong project execution.Additionally, Pembina 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 Montney 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 of regulatory approvals; advancing inter-project agreements with Coastal GasLink and LNG Canada; signing a heads of agreement with Samsung Heavy Industries and Black & Veatch; 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 a final investment decision. These include binding commercial offtake, obtaining third-party consents 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 some more detailed financial highlights for the 2023 fourth quarter and full year.
Thanks, Scott. As Scott noted, Pembina 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 Nipisi pipeline; higher tolls primarily on the Cochin Pipeline and Peace Pipeline systems, largely related to contractual inflation adjustments; and lower contribution from the Alliance Pipeline, primarily due to lower interruptible tolls and volumes. In Facilities, factors impacting the quarter included higher contribution from the PGI assets, primarily from the former Energy Transfer Canada plants, the Hythe Plant, and the Dawson Assets due to higher volumes; and higher revenue at Vancouver Wharves.In Marketing and New Ventures, fourth quarter results reflect the net impact of higher contribution from Aux Sable; 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 Nipisi 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 cost, 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 Nipisi pipeline, higher volumes on the Peace and Drayton Valley pipelines, higher volumes from PGI and lower volumes at the Redwater Complex.The fourth quarter contributed to full year 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, Pembina 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 $50 million of common shares and continue to reduce its leverage below the low end of the target range.At December 31, 2023, based on the trailing 12 months, the ratio of proportionally consolidated debt to adjusted EBITDA was 3.3x, reflective of our strong balance sheet and supporting a strong BBB credit rating.I'll now turn things back to Scott.
Thanks, Cam. In closing, we are enthusiastic about the future given the current momentum in the WCSB and expect continued volume growth through 2024 and beyond. Our broader outlook remains unchanged as we see the potential for mid-single-digit 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 TransMountain pipeline expansion; and potential new developments in the Alberta petrochemical industry; including significant incremental ethane demand associated with Dow's Path2Zero project. Given the scope and reach of our business, Pembina 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 take-or-pay or cost -of-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 5 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 Pembina 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.
[Operator Instructions] And your first question comes from the line of Jeremy Tonet from JPMorgan.
Just wanted to go into the Dow announcement a little bit more as far as this ethane supply agreement is 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?
Jeremy, Jaret here. Yes, great question. So super excited to obviously announce 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 Pembina's overall supply. It will require us to spend incremental capital with respect to getting that supply. We've spoken previously about RFS III. That was originally designed as a C3+ fractionator, but it has the optionality for us to put DS on it. So that would be a brownfield expansion.There are other opportunities at Empress and through PGI and/or Pembina wholly-owned extraction assets that we see opportunities. We also obviously see amounts of positive with respect to utilization across our asset base.And with 50,000 barrels of ethane, obviously, a bunch of C3+ comes along with that. So it is going to be a mix of brownfield and greenfield opportunities for Pembina and higher utilization across the board.And then on the AEGS pipeline, Pembina has announced that we're going to be 50,000 barrels. We fully expect that we're not the only contributor 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 in a better position to update you all on AEGS' expansions.
Got it. That's very helpful there. And is there any way to frame what the potential capital deployment sizing or time frame or sizing really could be for this?
Yes. Jeremy, it's Scott here. We've been progressing, as Jaret pointed out, multiple options. We're working the engineering and the economics of all of those. So I would say probably by midyear, 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.
Got it. Understood. And just one last one, if I could. Nipisi pipe and reactivation here, I was just wondering if you could speak a bit more on the market drivers to this and I guess commercial momentum here. What you see in the market? Is there potential to -- could this be fully filled up? What type of time frame could that materialize over? And what are the drivers here?
I'll take that again, Jeremy. So the drivers are the Clearwater formation. So a lot of activity in that neighborhood. And we expect the pipeline to honestly be 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 yes, fully see line of sight of having that 100% contracted by year-end.
And your next question comes from the line of Rob Hope from Scotiabank.
I want to stick on the Dow announcement and the supply [Technical Difficulty] in West Group. When you look at the options, 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 Bakken?
Yes. Rob, look, again, this ethane is going to be supplied from a mix of the existing portfolio as well as new. And the new ethane will come from some of the various projects that we're currently evaluating, as we discussed. There definitely is an option to move incremental barrels on Vantage out of the Bakken. So that is a very real possibility to supply.
Appreciate that. And then maybe just moving over to kind of the volume outlook for 2024, a number of moving parts, including, we'll call it, rather strong condensate pricing offset by weak AECO pricing. When you're talking to your producer customers, how do you think volumes progress through the year? Should we see a little bit of softness in the front part and then ramping up into LNG Canada in 2025?
Yes. Rob, I think we continue to believe in that mid-single-digit growth that we talked about. But we are monitoring producer CapEx budgets pretty closely and have ongoing discussions. And so, certainly, it's on the back -- it's on -- it's top of mind in terms of what producers are going to do throughout the rest this year. But to your point, obviously, we'd like AECO to be a little bit higher for our producing community. But with oil at $77 condensate premium and Canadian dollar earning over $100 for your condensate carries the day 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 AECO.
And I would just add to that, Rob, on top of the liquids market or the condensate market, obviously, the NGL market has bounced around a little bit. But certainly, December-January and into February here, we've seen some strength there. And obviously, the arb into the Far East markets continues to be open and supportive for that as well. So we do see that buffering the weaker gas prices as well.
And your next question comes from the line of Linda Ezergailis from TD Cowen.
Recognizing we'll likely get an update on Cedar LNG midyear. Just wondering how we might think about the bookings of cost estimates for the project recognizing that a few things have moved around, including foreign exchange since you first announced the project?
Yes. Linda, it's Cam here. I guess we'll continue to defer being very specific about that question until we can really tell the whole story around the opportunity. I mean, obviously, when we bought into that project, we announced the capital cost of in the mid USD 2 billion range. Obviously, the world has changed since then. And I think we all recognize that it's going to be higher than that.That said, when we look at Cedar from a global competitiveness standpoint, we see that it continues to stack up very well from a cost per ton basis against the North American alternatives into the global markets, reflecting both the capital intensity, but also the West Coast advantages in terms of shipping that Cedar enjoys. So recognizing that there's a desire for more specificity, we'll probably leave it at that until we can tell the full story.
Okay. And maybe as a follow-up, if you can help us understand, given all of what you just shared in terms of 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 were your initial returns higher and they've come down a bit? Is there anything that you can point towards directionally?
Yes. I would say from where we look at this project from this point in the development cycle, the economics of Cedar continue to reflect what we would have seen historically in terms of greenfield type returns for projects of this sort. They're clearly not where the brownfield opportunities are. And obviously, we've got a number of those as well. But they would continue to be in that same sort of historical range, that mid to high single-digit kind of range.
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 offtake agreements? And what sort of mix of take-or-pay versus fee-for-service or other attributes would you be looking for in any offtake agreements?
Linda, it's Scott here. I think really it's time. 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 due to time and the interdependency of so many different agreements on this project. In terms of our structure, recall 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.
And your next question comes from the line of Robert Catellier from CIBC Capital Markets.
I have a follow-up here on the ethane supply agreement. I'm wondering if you could explain the exposure that you have on that agreement to commodity prices and volumes.
Yes, Rob. I think that -- if you think about the way that ethane is contracted in Western Canada, it's obviously different than other parts of North America. And so generally speaking, the way that works is that it's ultimately for folks like us a fee-based structure. But the way that Pembina really makes money on this is through transportation and provision of the volumes through the rest of the asset base. So as we sit today through the conventional business, through the transmission business, through 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 C3+ that comes with those molecules when you extract it.
Right. So to the extent the market is short or tight and maybe short volumes or the price is up, that ultimately is borne by the counterparty.
That's correct.
Right. And then 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, et cetera, et cetera. Typically, we would expect any change of law or tightening of these regulations to have some cost sharing with your customers. But as -- it seems like a pretty, I guess, a continually evolving landscape as far as environmental regulation goes. But as you look over the horizon in the next 3 to 5 years, is there any substantial change to your cost structure that's not otherwise shared with shippers or producers?
Not at this stage, Rob. I mean, I think we're continuing to assess all the existing and pending regulations. We continue to work on decarbonization of all the assets and really understanding where we can get 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 what the implications are of that. But at this stage, there's no, what I'd call, material change in the cost structure.
Okay. Last question for me is, just are there any significant implications for Chevron selling their Duvernay assets in terms of your business development?
No major implications, Rob, actually. We're excited. We're going to support Chevron through the transaction. Chevron, I would say, has taken a modest approach to the development in the area. And we believe that 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 Pembina's infrastructure.
Yes. Rob, if you look back at, say, over the last 18 months, there's been 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, 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. You've seen that in the increased utilization across the PGI assets. So Chevron is a great counterparty. But we would expect potentially higher volumes over the relatively near future through an acquisition of a third party.
And your next question comes from the line of Praneeth Satish from Wells Fargo.
I guess 2 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?
Yes. Again, we don't have line of sight to where the rest of the ethane is coming from and in what phase and what time line, so potentially a question for others. But depending on where that ethane comes from, we would have an opportunity to move it on our pipelines. Again, we have the only C2+ pipeline in operations today, gathering lines. And so -- and we have a pretty big frac footprint. So there is the potential. But at this stage, we're not aware of where the next -- or where the rest of the ethane is coming from.
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+? Is there may be enough to consider an LPG export dock expansion? Or will it get railed into the U.S.?
It's Chris here. Yes, 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 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.
And your next question comes from the line of Robert Kwan from RBC Capital Markets.
I can start with the topic of the day with Dow. And so you talked about the potential to put a DS on the front of RFS III. What other capital should you see going into the system, whether its compression or deep cuts out in the field? And just under the agreement then with Dow, given you're still working through cost of everything, does the agreement specify a 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, with Dow?
Yes, Rob. 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. We are -- again, going back to the initial comments. We have a mix here where a significant portion will come from 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 pointed out potentially as an example incremental deep cuts, RFS III, DS. There's other opportunities that we just can't talk about at this stage that we're exploring.And so for us, it will 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 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 investments.
Got it. And Scott, can I just square your comments here 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 a statement that, that is going to be borne by Dow. So how does that square up just in terms of your obligations to supply?
Yes. 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, there's an arrangement there. But it's a supply agreement and we have the obligation to supply. So we have a capital cost element to that. But there's -- the price is fixed.
Okay. If I could just shift to Cedar. You listed a number of things that you've got to work through. One of them that you didn't list, though, is just around costs. So coming out of the FEED study, are 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 cost overrun risk? And specifically, you've talked about fixed price EPCs. 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?
Yes, 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 the vast majority of the cost, which -- again, we'll lay this all out if we 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, 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 Pembina is pipeline and transmission lines. And it's a 9-kilometer pipeline, a 10-kilometer pipeline.I think given our track record, I would hope that market has some confidence around our ability to deliver on that. I mean you just saw Phase VIII come in materially under budget. So we feel confident around doing our core business on this asset. And then, of course, on top of that, we have a typical project contingency and protection.So overall, we feel good mainly because of 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.
A quick one here just on the Alliance, Aux Sable deal. You've got HSR. But can you just comment on where you are in the Canadian Competition Bureau approval?
Yes, Rob. I would say that timing-wise, you can see that we reiterated our second half -- first half of 2024 time frame. You're correct. We've got the waiting period expiry on HSR in Transport Canada. I would say we don't have any better information at this point on the Competition Bureau process to refine that view anymore. Things are progressing as expected, as planned, but no sort of further visibility at this point to try and narrow that date.
And your next question comes from the line of Zack Van Everen from TPH.
Just going to Fort Sask frac market. 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?
Jaret here. The answer to your question 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 1. So the teams are obviously in deep negotiations with respect to annual deals. But the majority of our contracts at our fractionation complex are long term in nature, 5, 10-plus years. So unfortunately, where we can grab those opportunities, we do. But it is long term in nature.
But certainly, future frac negotiations continue to progress. And with RFS being the next frac in service -- RFS IV being the next frac in service, 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 it's really the next material frac expansion that we're aware of. And so those discussions continue.
Very good. Perfect. That's super helpful. And then, one on Cochin. It seems like Cochin and competing pipes saw oversubscribed shipper interest. I was curious if you could squeeze any more capacity out of that system with smaller capital-efficient solutions? Or maybe there's a bigger project you guys could do as well?
I'll take that again. So Cochin, since we've acquired that asset in December of 2019, we've increased the throughput by roughly, I think, 25%, 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.
And your next question comes from the line of Patrick Kenny from National Bank Financial.
Just on the Wapiti expansion, nice to see the commercial support there. Wondering if you could just update us on what other G&P expansion opportunities might be in the queue across your portfolio based on the customer activity levels that you're seeing in the field these days.
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 obviously increase the reliability of that asset, lower the carbon intensity, the Wapiti expansion that will utilize the asset gas transmission line that we acquired through the Energy Transfer Canada acquisition. We have other opportunities to do, I would call it, 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 I can't get into the specifics, but lots of opportunities for sure.
And then maybe from a tuck-in or M&A perspective, curious, Jaret, if you're seeing any shift in producer appetite for third-party gas processing services, just given the outlook for gas prices at least through the summer and maybe their need to secure downstream access and maximize the value of their liquids production within their overall netbacks.
Yes. I would say no material change in the market. There continues to be -- its very producer specific in terms of certain producers want to own and operate, and that's core to their business. And others look at what opportunities there are for mid-streamers to enhance their capital allocation decisions. And so, I would say it's -- those discussions are ongoing and always have been and it's 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 we do through PGI, obviously, we have to be on site with our partner. But we really want to make sure that we're focused on the geology, that we're buying processing assets that have long reserve life indexes, and then obviously contribute to the rest of Pembina's value chain.
And ladies and gentlemen, we have reached the end of our Q&A session. I would like to turn it back to Pembina's President and Chief Executive Officer, Scott Burrows, for closing remarks.
Well, thank you, everyone. Thanks to our staff that are listening in, to our customers. 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.
And ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.