Plains GP Holdings LP (PAGP) 2025 Q4 法說會逐字稿

Good day, and thank you for standing by. Welcome to the PAA and PAGP fourth-quarter 2025 earnings call. (Operator Instructions) Please be advised that today's call is being recorded.

I would now like to hand it over to your speaker, Blake Fernandez, Vice President, Investor Relations. Please go ahead.

Thank you, Victor. Good morning, and welcome to Plains All American fourth-quarter 2025 earnings call. Today's slide presentation is posted on the Investor Relations website under the News and Events section at ir.plains.com. An audio replay will also be available following today's call.

Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on slide 2. An overview of today's call is provided on slide 3. A condensed consolidating balance sheet for PAGP and other reference materials are in the appendix.

Today's call will be hosted by Willie Chiang, Chairman and CEO and President; and Al Swanson, Executive Vice President and CFO, along with other members of the management team.

With that, I'll turn the call over to Willie.

Thank you, Blake. Good morning, everyone, and thank you for joining us. Earlier this morning, we reported fourth quarter and full-year adjusted EBITDA attributable to Plains of $738 million and $2.833 billion respectively. 2025 was a pivotal year for Plains. The market environment presented multiple challenges, including geopolitical unrest, actions from OPEC to increase oil supply, and uncertainty on the economic impact from tariffs.

As highlighted on slide 4, despite these distractions, we remain focused on transitioning to a pure-play crude company, which also serves as a catalyst to streamline our operations and better position Plains for the future. This transition has accelerated through the sale of our NGL business, along with the recent acquisition of the EPIC pipeline now renamed Cactus III. These transactions enhance the quality and the durability of our cash flow stream while improving distributable cash flow and positioning us well for future market cycles.

2026 will be a year of execution in self-help with a focus on three initiatives. First, we remain on schedule to close the NGL divestiture near the end of the first quarter, pending Canadian Competition Bureau approval. Second, we're integrating the recently acquired Cat Street pipeline and expect to drive synergies related to that system to improve EBITDA. And third, we're streamlining the organization with a focus on efficiency and improving our cost structure.

Over the past several months, we have advanced our streamlining initiatives and are targeting $100 million of identified annual savings through 2027 with approximately 50% expected to be realized in 2026. The key drivers of these efficiencies are outlined on slide 5 and including reducing G&A and OpEx to reflect a more simplified business, consolidating operations, and exiting or optimizing lower-margin businesses.

One example that illustrates our focus on higher-margin businesses is the sale of our Mid-Continent lease marketing business in the fourth quarter of 2025 for a total consideration of approximately $50 million with minimal impact to EBITDA. This sale removes working capital needs associated with line fill, it simplifies operations with an improved cost structure while adding long-term contracts to our business. While this transaction is relatively small, it illustrates an opportunity that we have executed on to streamline our business, improve margins, and do more with less.

On the bolt-on acquisition front, in January, we acquired the WildHorse terminal in Cushing, Oklahoma from Keyera for a net cash consideration of approximately $10 million which includes an upward purchase price adjustment of approximately $65 million upon the closing of the pending NGL divestiture. This asset adds approximately 4 million barrels of storage adjacent to our existing terminal assets and is expected to generate returns well above our internal thresholds.

Looking to 2026 and as highlighted on slide 6, we are providing adjusted EBITDA guidance of 2.75 net to Plains at the midpoint plus or minus $75 million with an oil segment EBITDA midpoint of $2.64 billion net to Plains, which implies a 13% growth year-over-year in the crude segment. We expect $100 million of EBITDA from the NGL segment, assuming the divestiture closes at the end of the first quarter, and $10 million of other income.

We forecast Permian crude production to be relatively flat year-over-year in '26 with overall basin volumes remaining about $6.6 million at the end of the year, similar to end of 2025 levels. That said, we expect growth to resume in 2027 underpinned by more constructive oil market fundamentals driven by ongoing global energy demand growth and diminishing OPEC spare capacity.

Regarding capital allocation, we recently announced a 10% increase in the quarterly distribution payable on February 13 for both PAA and PAGP. On an annualized basis, the distribution represents a $0.15 per unit increase from the November level, bringing the annual distribution to $1.67 per unit, representing an 8.5% yield based on the recent equity price for PAA.

With the simplification and streamlining of our business, stable cash flow contributions from the Cactus III acquisition, and reduced commodity exposure following the NGL sale, we are modestly reducing our distribution coverage ratio threshold from 160% to 150%. This reflects improved visibility for our business, better aligns us with peers, and it paves the way for future distribution growth while still maintaining a prudent level of coverage.

Our targeted annualized distribution growth remains $0.15 per unit, and the lower distribution coverage gives us more confidence in our ability to deliver increasing returns to our unitholders. Al will cover specific CapEx guidance for the year, but we expect a meaningful reduction in gross spending versus 2025 levels, and maintenance capital will naturally decrease following the NGL divestiture.

We remain committed to our efficient growth strategy, generating significant free cash flow, optimizing our asset base, maintaining a flexible balance sheet, and returning cash to unitholders via our disciplined capital allocation framework.

With that, I'll turn the call over to Al to cover our quarterly performance and other financial matters.

Thanks, Willie. Slide 7 and 8 contain adjusted EBITDA walks that provide additional details on our performance. For the fourth quarter, we reported Crude Oil segment adjusted EBITDA of $611 million which includes two months of contribution from the Cactus III acquisition, partially offset by a full quarter impact of recontracting on our long-haul systems.

Moving to the NGL segment, we reported an adjusted EBITDA of $122 million, reflecting a seasonal uptick that was moderated somewhat by warm weather impacts on sales volumes and relatively weak frac spreads. A summary of 2026 guidance and key assumptions are on slide 9.

We remain focused on making disciplined capital investments and expect to invest approximately $350 million of growth capital and approximately $165 million of maintenance capital net to PAA in 2026. Key drivers for EBITDA year-over-year include full-year contributions from acquisitions, primarily Cactus III, efficiency and optimization gains partially offsetting the impact of the NGL sale, and recontracting as provided on slide 10. Importantly, I would note that while headline EBITDA will decline slightly from the divestiture, distributable cash flow is expected to increase approximately 1% driven by lower corporate taxes and maintenance capital. As illustrated on slide 11, we remain committed to generating significant free cash flow and returning capital to unitholders while maintaining financial flexibility.

For 2026, we expect to generate approximately $1.8 billion of adjusted free cash flow, excluding changes in assets and liabilities and excluding sales proceeds from the NGL divestiture. With regard to the potential special distribution previously communicated, we expect the Cactus III acquisition to mitigate a significant portion of the expected tax liability to unitholders resulting from the NGL sale. From this perspective, we now expect a special distribution of $0.15 per unit or less after closing and pending Board approval.

Regarding our balance sheet, in November, we issued $750 million in senior unsecured notes, consisting of $300 million due in 2031 at a rate of 4.7% and $450 million in 2036 at a rate of 5.6%. Proceeds were used to partially fund the EPIC acquisition. Additionally, in the fourth quarter, we paid off the $1.1 billion EPIC term loan assumed as part of the EPIC acquisition by issuing a $1.1 billion senior unsecured term loan at BAA.

As a reminder, since we invested $2.9 billion to acquire Cactus III, the majority of the proceeds from the NGL sale will be used to reduce debt. Post-closing, we expect our leverage ratio to trend toward the middle of our established target range of 3.25 to 3.75 times.

With that, I will turn the call back to Willie.

Thanks, Al. 2025 is a transformational year for Plains, and we are taking steps to further strengthen our company for the future. Despite a complex macro backdrop, we proactively executed several major transactions and implemented efficiency initiatives to position Plains as the premier North American pure-play crude oil midstream company. 2026 will be a year of execution and self-help as we focus on closing the NGL sale, advancing our efficiency initiatives, and driving synergies on the Cactus III system. Collectively, these actions will help position Plains more competitively for the future.

I also want to take this moment to express thanks to our Plains team, whose dedication and professionalism showed through and through as we also achieved our best-ever safety performance as measured by our best TRIR safety rate as well as the lowest severity of injuries as measured by total loss workdays. In closing, I would like to reiterate that we remain committed to our efficient growth strategy, simply stated, generate significant free cash flow, maintain a flexible balance sheet, and return capital to our unitholders.

I will now turn the call back over to Blake who will lead us into Q&A.

Thanks, Willie. As we enter the Q&A session, please limit yourself to two questions. For those with additional questions, please feel free to return to the queue. This will allow us to address questions from as many participants as possible in our available time this morning. The IR team will also be available after the call to address any additional questions you may have.

Victor, we are ready to open up the call, please.

(Operator Instructions)

Manav Gupta, UBS.

I actually wanted to focus a little bit more on the Cactus pipeline and all the synergy benefits you're talking. And also, I know this is not the right macro, but eventually, the macro will turn, and I'm trying to understand what's your ability to expand Cactus III without actually putting more pipe in the ground. If you could talk about some of those factors?

First, on the synergies question, the $50 million of synergies we disclosed, we believe we're already on run rate for that now. Roughly half of that was associated with G&A and OpEx reductions as well as removing things like insurance and other things that the pipeline had to keep because it was a private equity-backed entity. Those are gone, so half the synergies were achieved in the fourth quarter as we shed those costs.

The other 25% are associated with filling the pipeline with supply that we have doing shorter-term deals just to fill that available capacity associated with quality management. Those were ramping up now. So we would imagine during the first quarter, we'll be substantially there on the run rate for the $50 million, and we should hit that number this year.

As to your second question on the ability to expand the pipeline, our team, as we recontract the base pipeline to add term and improved rates for that uncontracted capacity now, in parallel, Chris' team is taking a look at all the capital-efficient ways to optimize our upstream connectivity, our downstream connectivity.

And then for incremental expansions of the pipeline that don't require a new pipe and that do require new pipe. So we're looking at the most capital efficient ways to do that. We should finish that during the first half of this year. And in parallel, like I said, we are recontracting for term the rest of the pipeline, and then we'll be in a position to discuss expansions with our customers, et cetera. But first is stabilize the base pipeline and then if look at capital efficient expansions from there in increments that make sense to grow with the base.

Manav, this is Willie. I think one key point that Jeremy highlighted is it's not a binary expansion at one time. We've got an opportunity to do it in phases and really match capacity to demand that's out in the market.

Perfect. My very quick follow-up is, can you also talk a little bit about the $100 million in cost savings through 2027 efficiencies and other initiatives that you're undertaking at the franchise leve?.

This is Chris Chandler. So the sale of our NGL business in Canada really creates a unique opportunity for us to rethink how our company is structured and organized. So that business, as you might expect, carried a fair amount of operational and commercial complexity that simply won't exist once the assets are sold. So we're taking a fresh look from top to bottom at how we're organized, where we're located, a fresh look at some of the maybe non-core businesses that might be better in somebody else's hands or, for example, outsourced to third parties that could do it more efficiently.

So it's really an across-the-board look that you don't get the opportunity to do this very often. As far as the capture rate, it's $100 million run rate by the end of 2027. So we expect to achieve $50 million of that in 2026 and another $50 million in 2027.

(Operator Instructions)

Brandon Bingham, Scotiabank.

Maybe first, just looking at the Permian Basin outlook and kind of some of the commentary you just went through. Just trying to harmonize it with some of the larger producer commentary from recent earnings calls. How is the sentiment among your producer customers? And maybe what are some of the current discussions like assuming that $60, $65 WTI scenario in your guide?

First, I would say that 60% to 65% is 10% higher than it was a few weeks ago. So it's a very volatile time period. But what I would say is the larger the producer, the less sensitive they are to the plus or minus $5 swings that we used to incur. So I'd say cautiously optimistic because if you look consistently across the producer landscape, what used to hold the Permian Basin flat was 325 rigs with less production.

Now it's 230 rigs. So you can see those efficiencies are working through the system there. What I would tell you is that they're working to preserve in inventory. They're working to continue to get more efficient with how they develop it and improve recoveries. All of those things are good for stabilizing earnings for us.

And we remain consistent that while 2026 may be flattish, we think a more constructive environment for 2027 and beyond for growth, and that's very consistent with taking a pause, getting better at doing things, becoming more efficient, so that continues to be the case for us. So I would say that's consistent with how we're discussing with producers.

And Brandon, this is Willie. I think a couple of other things to point out. As we develop these basins, it's an exercise in constraint removal. So one observation is gas has been tight, and there's a number of projects that are there to alleviate that. And when you leave the gas constraint, actually, the breakevens for the producers improve, which allows them to be able to be more durable going forward.

And I think just to reinforce your point, we've had some consolidation in the upstream section with a couple of the producers recently announced. And for us, we like that because it's -- it bolsters the producer environment to develop the basins in a more thoughtful way.

And I'm actually very encouraged by some of the technology improvements that some of the majors are focused on resource recovery. So when you factor all that in, we're very, very confident and constructive on the ability for the Permian to be a key part of the incremental supply for the world for quite some time. And I would expect growth to come back as fundamentals improve.

Very helpful. And then maybe just looking at the capital allocation priorities, I would be curious to hear if maybe there's a shift in any of them versus what they have been. And specifically thinking around the payout ratio, is that 150% level more so to just continue the bolt-on strategy or other priorities? Or is there room to maybe further reduce it and maintain that $0.15 per unit distribution growth cadence a little bit longer?

Brandon, this is Al. Our view on capital allocation has not changed. I think I noted in the prepared comments, there's two ways to look at it. We got the net proceeds coming from the divestiture. We've really redeployed that already into Cactus III. So the proceeds there will go to pay down debt.

When you look ahead post that, it's all the same viewpoint that we had before. Our primary way of returning cash to shareholders is going to be through distribution growth. That's part of the $160 million to $150 million. We're comfortable with the $150 million level. We think it's actually consistent with a large number of our peers.

And so we'll be looking to continue looking at bolt-ons where they make economic sense. Distributing cash through distribution growth. Secondly, we do have some preferred securities as well as common unit repurchases. Those will be more on an opportunistic basis.

Michael Blum, Wells Fargo.

Maybe you could stay on the distribution coverage conversation. I really just wanted to get a little more of your thought process on how you landed at 1.5 and not 1.4 or 1.3? Just exactly, is there any kind of formulaic way we should thinking about this? You mentioned some of your peers, but I can think of one peer off the top of my head that says 1.3 is the right coverage. So just trying to get a little more insight into your thinking on that.

This is Willie, Michael. When you think about how we came up with the $160 million, right? That was in November of '22, and it was intended to be a coverage threshold that was conservative, reflecting our focus on the balance sheet. I wouldn't try to read too much into the delta other than at $150 million, it's still a conservative approach to distribution. And for us, it sets a nice balance for us as we look forward on ability for multiyear distribution growth.

So I would look at it as a modest reset consistent with our peers as we go forward. We think we have a much more durable cash flow stream, and it's really set there to allow us to feel good about our multiyear distribution growth.

And then just wanted to ask on the growth CapEx of $350 million, I guess, twofold. One, can you give us any details about any discrete projects that make that up or just some color around what's in that number? And then is this a good way to think about a run rate going forward now that you're really focused in the crude markets?

Michael, it's Chris Chandler. So yes, our guide for 2026 is $350 million. That brings us into our more typical $300 million to $400 million range, which we do think is a good number going forward, absent any large investments, which we would call out separately. When I think about how we got to $350 million and comparing it to prior years, we, of course, finished up the NGL fractionator expansion last year in Canada. We finished up a number of Permian crude oil infrastructure projects, and we finished a project unload into wax crude in the Mid-Continent. So those obviously all brought the number down on a year-on-year basis.

As far as how we build up into the $350 million, we have a healthy Permian connection program that's ongoing. In 2025, we connected more wells than we connected in 2024, and 2026 looks to be on a similar pace so far. We're also, of course, doing some modest investment to integrate the Cactus III pipeline to capture synergies, as Jerry mentioned, with additional connectivity and opportunities for quality optimization and cross connecting between our other Cactus pipes for energy efficiency. And then we see some good opportunities to potentially invest capital into our Canadian crude oil business. We're pursuing a number of potential contracts that would underwrite expansions there and have assumed some of that moves forward in 2026 as part of our capital spending.

Jeremy Tonet, JPMorgan Securities.

I just wanted to take a step back here, and there's been some geopolitical developments recently, particularly what's been happening in Venezuela, and it seems like there could be a domino effect in a lot of different directions of what happens there. So I was just wondering if you might be able to share any thoughts on how things could improve how could it impact plans, flows on asset utilization or even repurposing of assets.

I mean, the idea around Venezuela, I think, of the initial response of 50 million barrels sold into the US Gulf Coast, a significant portion. You restructure some of the slates and get consistent with what maybe Pascagoula or the St. James refiners or the Houston refiners had run, that immediate impact was widening of Canadian differentials in the Gulf Coast, the other heavy sour differentials, the Mid-Con and Canada. That creates opportunities -- more opportunities for quality optimization, cross-border flows, and other movements.

Going forward, if you look out a few years, it may be at 200,000 to 300,000 barrels a day, that might change some buying habits that shouldn't be enough with the commodity prices where they are to change Canadian flows materially. They'll have to price to move. So that would probably be a little bit wider Canadian differentials than otherwise would have been. It would take materially more than that to probably repurpose pipelines. But if you look -- if you added 1 million barrels a day, that does different things, right?

That now may push Canadian barrels to the West Coast that may create other opportunities to repurpose pipes from the Gulf Coast to other markets to feed heavy sours into those. So I think it's -- there's no easy answer because first, you need stability in the government, you need substantial reinvestment. Near term, I think it creates some opportunities around quality management and use of our cross-border pipes. Intermediate term, it creates some logistical opportunities for us as well. But longer term, I think it's going to take substantial investment in time for repurposing, but we're certainly monitoring and paying attention to it.

Got it. That's very helpful there. And one other high-level question, if I could. Plains has been active in industry consolidation, bolt-on M&A, what have you over time. And I was just wondering from your perspective, Willie, where do you think -- what inning are we in right now for consolidation in the crude oil infrastructure industry, bolt-ons, larger consolidation, what have you?

Well, I would say it's not a perfectly smooth trajectory as we think about consolidation. And specifically for us, we've made a couple of large transactions. Our focus right now is really to execute on those. We look at all kinds of opportunities that are out there. So you can be assured that as we look at things we'll take capital discipline, on being able to acquire things.

But I do think there will be more opportunities that are out there. And frankly, to your earlier question, when you think about the macro and you look at the North American infrastructure, you asked about Venezuela. Everyone has a different outlook and view of what might happen there. I personally think it's going to be very challenged to get a significant amount of growth out of Venezuela, which leads us to a more constructive crude oil environment going forward. And when you think about the infrastructure that we have in ground and the ability to repurpose if it makes sense, there's a lot of new opportunities there.

And I mentioned this on one of the last calls, if you think about the basins that you want to be involved in, the Permian Basin, obviously, is key, close to markets, growth, low breakevens, but you also have Western Canada. And everyone is aware of the desire for them to go to the West Coast. And we stay very involved in potential of bringing more barrels down to the US.

So there's a lot of these opportunities, and you can expect us to stay on track at looking at those with financial discipline.

Keith Stanley, Wolfe Research.

I wanted to ask on coverage. So the release specifically says that the change in threshold to 150% provides a multi-year runway for $0.15 increases. So I want to confirm, should we interpret that as the plan would be $0.15 increases for at least two more years? And if that's right, it implies a fair amount of growth since you'd have to stay above that 150%. So can you just talk to some of the growth drivers you see in the next -- in '27 and '28 that would support that?

Yeah, Keith, this is Willie. You're very astute as you did your calculations. The message we wanted to send is we have the ability to continue to grow beyond 2026. So if you think of our EBITDA this year, we've got $100 million of NGL contribution. And as you think about '27 plus, we've got self-help that chews up easily half of that.

Our comments earlier about additional growth in the Permian gives us confidence in that, and we know we're going to be able to extract additional efficient growth synergies out of that so -- out of our asset base. So we are telegraphing that we think we can grow beyond 2026.

Okay. Great. And then one other coverage one. So you've talked to the rationale for 150% of DCF. When you assess where you want to go from a coverage perspective, do you look at it on a free cash flow basis, too?

Because you have pretty steady $300 million, $400 million a year of investment capital. Just how do you look at it, I guess, on a free cash flow perspective as well?

Keith, this is Al. We've really said it based on DCF in the view that the DCF coverage of, say, 160 or now 150 would allow us to fund what we would call routine organic capital, that $300 million to $400 million kind of range that we think is more of a normalized level, plus a small bit for bolt-ons. So we think of it more of the coverage funding routine investments. Clearly, if we see investments that are outside of what is routine or larger, we'll use the balance sheet for that.

So it's not a precision on free cash flow, it's really -- or a percentage of free cash flow, but we are allowing for that kind of self-funding of what we think is a routine kind of profile of investment capital.

John McKay, Goldman Sachs.

I want to touch on the long-haul Permian volume guidance for a second. It is a little -- maybe if you can just talk a little bit about the year-over-year bridge. I think it is a little stronger than what we were looking for, but maybe the overall margin is intact. So a little bit of that volume versus margin mix and then bridging us to that pretty high '26 number.

There's 3 components to it. First, you've got the full year run rate of the Cactus III integration into the system. Second, you've got a significant uptick in contracted capacity on the basin pipeline system, and so that would explain some of the lower margins just because the rate from Midland to Cushing is lower than that to the Gulf Coast. And then third, you'd have the BridgeTex Pipeline full-year run rate since that was acquired during partially half of the year.

That's very helpful, Jeremy. I appreciate that. Second one, maybe just looking a little more near term, what do you guys see in terms of storm impacts on volumes across the board? I think the visibility on the gas side has been clear. But maybe just walk us through what you saw in the last week or two and where the recovery stands right now?

To start with the recovery, that's already happened. So it was roughly a 7- to 10-day period when you have back-to-back freezes. A lot of that impacted the gas infrastructure and made it difficult. And then once gas infrastructure is impacted, it shuts in the crude.

So we saw almost like a reverse checkmark type recovery, went down and slow to come back. But we'd say -- I would say that basin as a whole probably lost 10 million to 12 million barrels of production. The crude side and NGLs maybe half that over that 7- to 10-day period, but we're out of that trough and have been for a few days.

And that's all been considered in our guidance. So just for the record there, that impact has been considered.

Sunil Sibal, Seaport Global.

Most of my questions have been hit, but just a couple of clarifications. So in regards to your lowering of distribution coverage to 150%, so obviously, you more contracted cash flows coming in through Cactus, but I was kind of curious if there is anything else in terms of how you manage your other assets in terms of contracting that we should be thinking about there?

Sunil, this is Al. No, I mean, we are comfortable with the $150 million. We think the crude segment is a stable cash flow stream. Clearly, the EPIC contract is -- our pipeline is highly contracted. But as we look at it, we think the $150 million coverage is actually still remains a conservative coverage level relative to our company.

And we also think it funds what we -- I described as a routine kind of investment capital going forward.

And then I think in your prepared remarks, you mentioned about some storage acquisition, the Wildhorse House terminal. Could you walk through that a little bit. Again, I think you said 4 million barrels of storage, but what's the approximate cost for that?

Sunil, this is Jeremy. Here's what I would say. So that's 4 to 5 million barrels functional right now. It is adjacent to our existing facility. Our net cost is anticipated to be $10 million. It may take us some time to integrate the facility. It has got an existing operation today.

We feel like we have sufficient demand. Our existing Cushing facility is fully contracted to downstream partners, and we would just think of this as an addition to that business with a low-cost basis for us. We could not build those tanks for $10 million, so we're excited about the opportunity to grow our relationships with our customers.

AJ O'Donnell, TPH.

Just one question for me. I'm not sure where the development of Venezuela kind of fit on the timeline of your budget. But just curious, as you sit here today and think about where dips are and how quality dips are moved. Just curious how you think about the market-based opportunities trending above or below that $50 million mark that you outlined in your deck.

What I would say is the current market reflects what our budget is. So those happened towards the end of last year, giving us the opportunity to lock in spreads across the board. So it significantly derisks the opportunity for us, and they've moved out. So things move all the time, but when you have a movement like this, it gives you the opportunity to lock some things in. So I'd say it firmed up part of our plan.

Jeremy Tonet, JPMorgan Securities.

Just a couple of quick ones, if I could add. We talked a good amount about the 60% of the business in the Permian. But just wondered if you could provide maybe a little bit more color on the other 40% of the business and what trends you're seeing there? And I get there's cross currents or it's influenced by cost cut savings you're seeing there and that will have some impact. But just how do you think about volumes and EBITDA for that other 40% of the business trending over time?

Jeremy, what I would say is let's start from the north. Excited about Canada, as Chris mentioned, opportunities around our rainbow system to expand our Rainbow System, seeing more activity. The rest of the business is largely flat in Canada. So if you take our Rockies position, everything north of Cushing and West of Cushing, that's relatively stable and contracted. So flattish would be the view of that position. Cushing throughput continues at all-time highs year-over-year for us.

So we think those assets in Cushing and the refinery feed assets, consistent with the refiners performance, that should perform well this year. The South Texas is really somewhat of an extension of the Permian Basin business. It's a wellhead gathering business with trucking to support it. And so that step down from the Cactus contract that impact that business as well. But as far as volumes and opportunity set following Ironwood, Cactus III, and the integration with our legacy system, we're excited about what we see in South Texas.

Now east of Cushing, the Capline system in Liberty and Mississippi, those are assets we're looking to fill longer term and working on some longer term contracting. And St. James continues to perform and with the expectation of growth in the US Basin over the next 18 months to continue to come through to our St. James facility. So I think we've got exciting things across that platform.

It's not as volatile, and it's not as much growth in the other, but you'll see some potential capital investments there as we get contracts to support it.

Got it. That's helpful there. And just one last one, if I could. As it relates to the sensitivities for the 100,000 barrels per day change in total Permian production having a $10 million to $15 million impact on the business. Just wondering if there's any more color you could provide there if -- how that sensitivity might change if volumes grow over time, is it linear or could there be an inflection realizing there's an interplay with differentials there? But just any other color, I guess, on how that could fall out?

Jeremy, here's what I'd say. I think the business is very large, right? So when we talk 100,000 barrels a day out of a basin that's over 6 million barrels a day. The impact of the gathering system is going to be relatively modest. So that $10 million to $15 million per 100,000 barrels a day probably still applies that the integrated benefit may grow over time.

I think that's more of the impact of the price to go to Midland. What could change it might be on the margin, some differentials around WTL and WTI. But I think just because of the size of that business, it's probably going to stay in a fairly tight band.

The impact might be to the long-haul margins since we've been reset to what is the new market, our expectation would be those would widen out over time. So you might see more of an impact to the long-haul business.

We'll see you next time, Jeremy.

We're not showing any questions in the queue right now. I will now like to hand it back over to management for closing remarks.

Thanks, Victor, and thanks to all of you for dialing in. We look forward to visiting with you on the road, and I hope you have a safe weekend. Thank you.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.