Pembina Pipeline Corporation (PBA) Q4 2023 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen and welcome to the 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, Lady [ph] 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 we may express or imply today are subject to risks and uncertainties which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see the company's management's discussion and analysis dated 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 will now turn things over to Scott to make some opening remarks.

Thanks, Cam. We're pleased yesterday to report our fourth quarter results which include 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 Western Canadian sedimentary basin could be seen by more than 4% year-over-year increase in second half volumes and the conventional pipeline business. In 2023, Pembina progressed [indiscernible] by sustaining and enhancing our business through various accomplishments we shared throughout the past year, including signing new contracts in the Peace Pipeline System, signing new and/or extending existing contracts with 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 co-generation facility at PGIs K-Bob III Plant [ph]. In the fourth quarter, positive developments continued including the announcement of a $3.1 billion acquisition of Enbridge’s [ph] interest in Alliance and 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 of them will further enhance our growing franchise. We continue to expect the acquisition to grow 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 Dallas path-to-zero project [ph], Pembina has entered into a long-term agreements to supply up to 50,000 barrels per day of ethylene and for the associated transportation on the Alberta Ethane Gathering System. The path-to-zero project [ph] is an important development for the WCSB [ph] 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 [indiscernible] on a Croatian 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 has now contracted for more than half the capacity on a long-term basis, with line of sight to the asset being fully contract by the end of 2024. On the meter project fund [ph], we continue to progress our Phase VIII Peace Pipeline expansion, and our RFS IV expansion 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 of Phase VIII is another example of supporting Pembina’s track-record of strong project execution. Additionally, Pembina gas infrastructure has provided as approved, an expansion at the [indiscernible] 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 expansion is being driven by strong customer demand, supported by growing 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 substantially completed several key project deliverables, including obtaining material regulatory approvals, advancing inter-project agreements with Coastal Gaslink and LNG Canada, signing a heads-up 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 scheduled driven interconnected elements that require resolution prior to making the final investment decision. These include binding commercial off-take, 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 in more detail financial highlights for the 2023 fourth quarter and full year.

Thanks, Scott. As Scott noted, Pembina’s record 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 of the Peace Pipeline System, Drayton Valley Pipeline and on the recently reactivated Nipisi pipeline, higher poles, primarily on the Cochin Pipeline and Peace Pipeline Systems, largely related to contractual inflation adjustments, and lower contributions from the Alliance Pipeline, primarily due to lower interruptible poles and volumes. In facilities, factors impacting the quarter included higher contribution from the PGI assets, primarily from the former energy transfer Canada plants, the highest plant and the Dawson asset due to higher volumes, and higher revenue at Vancouver Works. In marketing and new ventures, fourth quarter results reflected 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 settlement provision and associated legal fees incurred in the fourth quarter of 2022, all 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 was 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 Green 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 our 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 the leverage below the lower end of the target range. At December 31, 2023, based on the trailing 12 months, the ratio of proportionate consolidated debt to adjusted EBITDA was 3.3x, reflective of our strong balance sheet and supporting a strong triple B 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 expected 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 Trans Mountain Pipeline Expansion, and potential new developments in the Alberta petrochemical industry, including significant incremental ethane demand associated with path-to-zero project [ph]. 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 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 Pembina and the rest of our industry do to ensure responsibly produce energies available to meet growing global demand. Thank you for joining us this morning. Operator, please go ahead and open up the line for questions.

Thank you. And ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] And your first question comes from the line of Jeremy Tonet from JPMorgan. Your line is open.

Hi, good morning. Just wanted to go into the Dow announcement a little bit more, as far as this ethane supply agreement is concerned. I am 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 investment here? Just trying to get a sense for what the project economics could look like here?

Good morning, Jaret here. Yeah, great question. So super excited to obviously announce our contribution to Dows 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. You know, we've spoken previously about RFS III, that was originally designed as a C3 plus fractionator but has the optionality for us to put DS [ph] 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 a massive positive with respect to utilization across our asset base. And with 50,000 barrels of ethane, obviously, a bunch of C3 plus 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 AX [ph] 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 AX [ph] expansions.

Got it. That's very helpful there. And is there any way to frame what the potential capital deployment sizing or timeframe, or sizing really could be for this?

Yes, Jeremy. It’s Scott here. We've been progressing, as Jaret pointed out, multiple options -- you know, we're working the engineering and the economics of all of those. So I would say, 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.

Got it, understood. And just one last one, if I could. The Nipisi pipe and reactivation here, just wondering if you could speak a bit more on the market drivers to this -- and I guess, you know, commercial momentum here or what you've seen in the market, is there potential to -- you know, could this be fully filled up? What type of timeframe 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 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 to having that 100% contracted by year-end.

Got it. That's helpful. I'll leave it there. Thanks.

Thank you. And your next question comes from the line of Rob Hope from Scotiabank. Your line is open.

Good morning, everyone. I want to stick on the Dow announcement in the West Groups below [ph]. 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? So 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, like -- 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.

Alright, appreciate that. And then maybe just moving over to the kind of the volume outlook for 2024; a number of moving parts, including we'll call it rather strong economy [ph] pricing offset by weak Echo [ph] pricing. When you're talking to your producer customers, how do you think volumes progressed through the year so we can see a little bit of softness in the front part? And then, the ramping up into LNG Canada in 2025.

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 -- it's top of mind in terms of what producers are going to do throughout the -- they arrested here [ph]. But to your point, obviously, we'd like Echo [ph] 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 Echo [ph].

And I would just add to that, Rob on top of the liquids market of 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 [ph] into the Far East markets continues to be open and supportive for that as well. So, we do see that that buffering -- the weaker gas prices as well.

And your next question comes from the line of Linda Ezergailis from TD Cowen. Your line is open.

Thank you. Recognizing we'll likely get an update on Cedar LNG in mid-year. Just wondering how we might think about the book-ends of cost estimates for the project recognizing that a few things have moved around including foreign exchange since you first announced the project?

Yes. Thanks, 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-US$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, you know, 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 there is 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.

Thank you. And just maybe commercially as well, recognizing that there is a few moving parts. Can you talk about what the potential sticking points are about getting different 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?

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 -- is just due to time and interdependency of so many different agreements on this project. And 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.

Thank you.

Thank you. And your next question comes from the line of Robert Catellier from CIBC Capital Markets. Your line is open.

Good morning, everyone. 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. 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, you know, 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 is -- on this is through transportation and provision of the volumes through the rest of the assets 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 plus that comes with those molecules, when you extract it.

Alright. So to the extent the markets short or tight, and the -- you know, maybe short volumes or the price was up, but 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 [ph] of additional costs for some of the emerging regulations and amended methane regulation, for example, clean fuel regulation, etcetera, etcetera. You know, 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, and as far as environmental regulation goes. But as you look over the rise in the next three to five years, is there any substantial change to your class 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 decarbonisation 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 of that. But at this stage, there is 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 [indiscernible] assets in terms of your business development?

No, 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 resource 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 acquires 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 increase utilization across the PGI asset. 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.

Okay, thank you. And congratulations on all your business momentum.

Thank you.

And your next question comes from the line of Satish [ph] from Wells Fargo. Your line is open.

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 [ph] 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 ethane is coming from, and in what phase and what timeline; so potentially a question for others. But depending on where that ethane comes from, we would have an opportunity to move in on our pipelines. 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 don't -- 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 pluses there? Maybe enough to consider an LPG export dock expansion or will it get railed into the US?

It's Chris here. Yes, right. 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 for 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.

Got it. Thank you.

And your next question comes from the line of Robert Kwan from RBC Capital Markets. Your line is open.

Good morning. If I can stop and start with the topic of the day [indiscernible]. So you talked about the potential to DF [ph] on the front of RFS III. What other capital should you see going into the system whether it's compression or deep heads out in the field? And just under the agreements and 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?

Rob, you know, I have to be careful with 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 -- you know, as an example, incremental deep cuts, RFS III. There is 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 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, 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 has cost of service in the province but if you have to do that there was the same 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 was providing the ethane; there is 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 is -- the prices 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 field study, you're comfortable with where those costs are; how you're going to manage the risk, and it really is now how do you deal with a 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 [ph] 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?

Rob, I'll start there and Stuart, 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's 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 you're 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. The vast majority of that price has been pushed off onto our EPC contract, the remaining con -- price that's on risk for Pembina is pipeline and transmission lines. And you know, it's a 9 kilometer pipeline, 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 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.

I’ll just finish a quick one here just on the Alliance; Aux Sable deal. You've got a HSR but can you just comment on where you are on the Canadian Competition Bureau approval?

Yes, Rob. I would say that timing wise, 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 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.

Okay. Thank you.

Thank you. And your next question comes from the line of Zack [ph] from TPH. Your line is open.

Just one question. Just going to the [indiscernible] 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 spot rates moved up? And then, as you talk to producers, are frac constraints becoming more and more of a concern?

Yes, good morning. 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 that are fractionation complex are long term in nature, you know, 5 to 10 plus years. So, unfortunately where we can grab those opportunities we do, but it is long-term in nature.

But certainly frac -- future frac negotiations continue to progress. And with RFS being the next frac in service; RFS IV being the next frac in service -- you know, 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 material frac expansion that we're aware of; and so those discussions continue.

Okay, perfect. That's super helpful. And then, one on Cochin. It seems like Cochin and [indiscernible] 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 is 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% to 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.

Okay, perfect. Super helpful as well. That's all I had for today. Thanks, guys.

Thank you. And your next question comes from the line of Patrick Kenny from National Bank Financial. Your line is open.

Yes, good morning guys. Just on the Wapadi [ph] expansion, nice to see the commercial support there. I am wondering if you could just update us on what other GNP [ph] 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 co-gen [ph], which is going to obviously increase the reliability of that asset, lower the carbon intensity, the Wapadi [ph] expansion that'll utilize the acid gas transmission line that that we acquired 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 this 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 net backs.

I would say no material change in the market. There continues to be -- it's 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 midstreamers [ph] 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 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 thought 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.

Okay, that's great. Thanks, guys.

Thank you. And ladies and gentlemen, we have reached the end of our Q&A session. I would like to send it back to Pembina’s President and Chief Executive Officer, Scott Burrows, for closing remarks.

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.

Thank you, Scott Burrows. And ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.