Plains All American Pipeline, L.P. Aktie

Good day, and thank you for standing by. Welcome to the PAA and PAGP Second Quarter 2026 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Blake Fernandez, Vice President of Investor Relations. Please go ahead.

Thank you, Danny. Good morning. Welcome to Plains All American Second Quarter 2026 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 consolidated balance sheet for PAGP and other reference materials are in the appendix.

Today's call will be hosted by Willie Chiang, Chairman, CEO and President; Al Swanson, Executive Vice President and CFO; and 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. This morning, we reported second quarter adjusted EBITDA attributable to Plains of $738 million, which puts us on track to deliver our full year EBITDA guidance of $2.88 billion, plus or minus $75 million for 2026. Al will cover more details on our results in his portion of the call. The conflict in the Middle East and supply disruptions from the Strait of Hormuz illustrate the importance of reliable, secure and responsibly produced energy.

We believe this increases the value of existing infrastructure, and we are well positioned to help play a critical role in meeting global energy demand well into the future. While the macro environment has been volatile, we are successfully executing on our 3 key initiatives for the year. In May, we closed on the sale of our Canadian NGL business, bringing our leverage down to 3.3x. Additionally, we have captured our targeted Cactus III synergies, which will enhance our connectivity to the Corpus Christi market and oil exports longer term. Finally, we expect to realize $50 million of efficiencies across the organization by year-end 2026, along with an additional $50 million by the end of 2027.

Strong producer activity and customer demand, coupled with our premier crude oil footprint are creating new organic investment opportunities. As we outlined in our June press release and detailed on Slide 5, we increased our growth capital spending for 2026 from $350 million to a range of $400 million to $450 million. These are predominantly quick hit projects that will contribute to the 2027 EBITDA and will generate a rate of return above our hurdle rate. This includes a further build-out of our Permian gathering system to service additional dedicated acreage in the Midland and Delaware Basins.

The acreage is backed by several high-quality producers and spans multiple counties. This brings our POPB JV total dedicated Permian acreage to approximately 5.1 million acres. Additionally, we're expanding our Canadian gathering systems. The additional capacity and connectivity will support strategic projects in the Clearwater and the Duvernay formations and are backed by producer commitments. Finally, we have sanctioned a very capital-efficient expansion of the Cactus III pipeline, adding an additional 75,000 barrels a day capacity. This brings the total capacity of the line to 725,000 barrels a day. The expansion will come online by the end of this month and will support increased demand for export barrels out of the Corpus Christi market.

We continue to evaluate additional investment opportunities, both organic and inorganic that strengthen our portfolio and complement our existing asset base. With regard to Permian production, we now expect approximately 100,000 to 200,000 barrels a day of growth in 2026 versus 2025 on an exit-to-exit basis. Upside from our previous forecast of relatively flat production is mainly due to natural gas egress coming online earlier than expected. Importantly, the ramp-up in Permian oil production will create meaningful momentum into 2027 while having minimal impact to EBITDA this year.

Our capital allocation framework and efficient growth strategy remain intact. We have a commitment to capital discipline to optimize our asset base and maintaining a very flexible balance sheet while returning significant cash to shareholders. With that, let me turn the call over to Al to cover our quarterly performance and other financial matters.

Thanks, Willie. Slides 6 and 7 contain adjusted EBITDA walks that provide additional details on our performance. For the second quarter, we reported crude oil segment adjusted EBITDA of $690 million, representing a significant increase from the first quarter level. This was driven by a combination of Cactus III synergies, efficiencies, market-based opportunities and the absence of headwinds from the first quarter. I would note that second quarter results include approximately $14 million of one-off environmental remediation expenses. Moving to the NGL segment. We reported adjusted EBITDA of $40 million, which reflects the mid-May closing date on the sale of the business.

We are contemplating removing NGL segment EBITDA from our reporting in the third quarter and instead reporting adjusted EBITDA with one segment. A summary of 2026 guidance and key assumptions are on Slide 8. As Willie outlined, we raised growth capital to a range of $400 million to $450 million and increased our Permian production forecast to 100,000 to 200,000 barrels a day exit to exit. Maintenance capital was decreased to $175 million, largely due to the timing of the NGL sale. Regarding our pipeline loss allowance revenue, we are approximately 70% hedged for the balance of the year at an average WTI price around $62.

We plan to disclose our 2027 hedge position in February in conjunction with our full year outlook. As illustrated on Slide 9, we expect to generate approximately $1.75 billion of free cash flow in 2026 and return significant capital to unitholders while maintaining financial flexibility. Our pro forma leverage ratio at the end of the second quarter was 3.3x, reflecting approximately $2.9 billion of debt reduction driven by the NGL divestiture. With that, I will turn the call back to Willie.

Thanks, Al. Slide 10 highlights the 7% compounded annual growth of our crude over the past few years. Our efficient growth strategy and the sale of the NGL business position us well to execute through a range of market environments, generating a more durable cash flow and creating long-term value. We continue to build momentum into 2027 with increasing Permian production and a strong balance sheet with leverage at the low end of our target range.

Our capital allocation framework priorities remain the same: one, return cash to unitholders through our targeted $0.15 per unit annual increases; two, execute on accretive bolt-on acquisitions and organic CapEx; and three, maintain a strong balance sheet with financial flexibility. We have already identified and expect to capture an additional $50 million of streamlining costs in 2027, and we are well positioned to capture potential tailwinds from the volatile oil macro environment. With that, I'll turn the call over to Blake to lead us into Q&A.

Thanks, Willie. [Operator Instructions]

With that, operator, please open the call for questions.

[Operator Instructions] Our first question comes from Gabriel Moreen with Mizuho.

Just wanted to ask about the revised CapEx, which I know came out a couple of weeks ago. Can you just talk about this level of $400 million plus in investment capital? Maybe how sustainable you think that will be given that some of it's Canadian, some of it's Permian, some of it's Cactus. Just curious how you're thinking about in '27 and beyond?

Sure. Gabe, it's Christopher Chandler. So Willie laid out in our slides also show the drivers that led us to change the guidance for 2026. Some of those are typical 18- to 24-month projects. So the spend will carry into '27 and maybe a little into '28. The way I think about it is I don't expect 2027 to look significantly different than 2026, but it is trending a little higher than our historical $300 million to $400 million range net to Plains. So we'll provide 2027 guidance, obviously, when we provide full year guidance in late January, early February.

And then maybe if I could just ask about the Cactus expansion and adding the 75,000 barrels a day. Just how long do you think that takes to fill? And to what extent can you keep adding these bite-sized expansions to Cactus going forward before you have to contemplate something much bigger than that?

Gabe, it's Jeremy Goebel. To answer your question, our marketing affiliate can fill the space now and capture the volatility that we're seeing. The expectation is to contract that over time when we see the market. So the reason we executed on it earlier than expected is you saw a lot of volatility, you saw growing production. You saw a really short time period, very capital efficient. And you see on the demand side, new buyers on the market. So our marketing affiliate can fill that role until someone wants to take the space from us. So we can fill it quickly and then turn it to a term basis, which is our ultimate goal.

And then to your question on are there other opportunities. Our team continues to evaluate capital-efficient opportunities, and we'll update you as we have them.

Our next question comes from Manav Gupta with UBS.

I wanted to go -- I know it's a little early, but I was thinking maybe you could talk a little bit about how 2027 is shaping up for you, the puts and takes, especially given the number of new pipelines expected, which will alleviate the Permian egress problem. So that crude could come to the market. So help us understand the puts and takes for 2027 versus 2026.

Manav, it's Willie. Let me try to address this. We're not going to give you guidance on '27 because the world continues to evolve. What we really want to convey to you is that longer term, whether it's the end of '26, early '27 is really going to be determined by how things shape up in the Middle East. There remains a lot of uncertainty, as everyone knows. The oil markets are very extreme. But as we view this, as the longer this goes, the more you draw global inventories to low levels, the more important North America is going to be to providing fuel for the rest of the energy to the rest of the world.

So everything we're doing is positioning us to be able to capture that when it comes. And you tell me the oil price, you tell me when things resolve, we can easily put a number together, but that's probably the extent I'll share on what our views are other than it being very constructive. And we've got a lot of momentum going into '27.

Perfect. My quick follow-up that I just wanted to understand from you is that your balance sheet is fixed. I think earlier in the year last year, you were looking at more bolt-on opportunities. Now I think you have looking at more organic growth projects also. Can you help us understand the balance between future growth driven by bolt-ons versus organic opportunities?

Manav, this is Willie again. The answer is we look at all of them. We've got lots of levers to pull. If the organic opportunities present themselves, we do it. If it's the bolt-ons, we execute on those. I'm really pleased where we are with our balance sheet where it is and the ability to pull levers. There are lots of different things, whether it's bolt-ons, whether it's CapEx, returning more cash to shareholders and even taking out the pref. Those are some of the options that we have. So it's a good position to be in, and we'll play the right card when the time comes.

Our next question comes from Praneeth Satish with Wells Fargo.

So just going back to the guidance, you raised the exit-to-exit Permian production growth by 100,000 to 200,000 barrels per day on improving gas egress. But I guess your -- and you kind of had strong Q2 results, but you left the 2026 EBITDA guidance unchanged. I guess intuitively, I would have expected at least some of those flush volumes to reach your system and contribute to earnings upside this year. So maybe you can just help us understand why the higher volume outlook doesn't necessarily translate into higher EBITDA guidance for this year and how you're thinking about the timing of when you realize those benefits?

Yes. This is Al. One quarter -- first quarter crude was kind of the low point for us. 2Q, we reported the $690 million I mentioned, which is up over $100 million from the first quarter. Our guide at the midpoint currently for the second half is above the $690 million. The math would say it'd be in the low $700s. So we've modeled in a very strong kind of exit to the year. We do believe that we will be seeing and capturing volumes. We had a bit of that in already, but we do expect really that this sets us up for the momentum that Willie mentioned for 2027 more so than "a raise" for the second half of the year since we've already modeled a pretty strong second half of the year.

Got you. That's helpful. And then maybe switching gears on the Cactus III expansion. So you guys have one of the last meaningful brownfield expansion opportunities in the Permian with Cactus. So I guess I'm just trying to understand how you balance adding incremental capacity versus just kind of maintaining a tighter market where you could benefit from stronger recontracting rates as it's been a tough slog the last few years. So I mean, I'm sure you've done some internal analysis on that trade-off. But I guess, with you going forward with this expansion, can we assume that the expected returns are compelling enough, I guess, to outweigh the benefits of a tighter market? Just how should we think about that?

Praneeth, good question. This is Jeremy. First of all, the 75,000 barrels a day won't change the market. And our outlook for production is substantially higher than 75,000 barrels a day. So the market from a supply and demand takeaway will be net tighter. The economic returns is very capital efficient that's not in question. They'll be very good. From our standpoint, we're executing on it.

Basin is very well contracted. Cactus I is very well contracted. Cactus II is very well contracted, and we're working to continue on Cactus III. So we don't think this impacts our ability to contract at strong rates across the system. And we think the volatility will present some opportunities to pay for the expansion in a short period of time and give us the opportunity to contract more space.

Our next question comes from Jeremy Tonet with JPMorgan Securities.

This is Francina on for Jeremy. Just wanted to dig a bit deeper on the guide that appears to kind of present declines outside of regions other than the Permian. Can you walk us through what you're seeing with volume expectations and kind of where that leads us in terms of puts and takes to the current maintained guide?

Sure. This is Jeremy. Look, we're seeing increased activity, the Permian has added 30 rigs from the trough. The Eagle Ford has added 10 rigs. The Powder River Basin is up 33%, so from 9 to 12 rigs. Canada continues to grow. So we're seeing opportunities across the system as evidenced by the expansion capital across the system. So from our standpoint, we're cautiously optimistic that, that will continue, and it should be good for both our assets in the Permian and outside the Permian. As for the guide, I think Al covered that.

We are certainly in position to continue to execute as volatility. The most volatile piece was the second quarter. The third quarter price volatility was slower. Volatility in margins across the regions got pretty narrow. It's just a different quarter. And so that the same situation because ships are moving all over the place could represent itself in the third and fourth quarter. So we certainly expect to continue to do as well as we can. But right now, we're maintaining guidance flat, but we think we're going to execute on what we've already put in the plan and hope to beat it.

That's helpful. And then I wanted to also touch on what you're seeing for the Canadian organic growth opportunity set and whether those opportunities more so present near term or longer term, if you could talk about that.

Sure. We're very excited about Canada. The Clearwater around our Rainbow asset, we are continuing to add capacity. And every time we add it, it gets full. So we're excited about it, and those are long-term contracts. Same with our Rangeland asset, which sits in the Duvernay, and we can bring those either north to Edmonton or south to the U.S. markets. So both of those areas are seeing capital. Our Manitou asset, which we haven't talked about much, is seeing activity -- substantial activity.

There may be an opportunity to partner with some of the egress that's coming out of Canada. So I think we see a lot of opportunities in and around our gathering footprint and how that might fit with assets like our Cushing terminal or our Capline assets downstream. So I think we're excited about Canada and knock-on effects for the rest of our business.

Our next question comes from Spiro Dounis with Citi.

I want to start off first with market-based opportunities. Can you maybe talk through the outlook into the second half of '26 and maybe where you still expect to see some areas for opportunities? And kind of just curious how you're thinking about differentials, volatility, curve structure, storage and how much of that is contemplated in the guide here?

This is Jeremy. We're not forecasting market-based opportunities other than what we've captured. So I think from our standpoint, if those opportunities present themselves, we will. We can play time, quality and location spreads across the system, and we will. And so from our standpoint, we feel very well positioned with where the guide is. And as volatility presents itself, we'll capture it just as we did in the second quarter.

Got it. Second question, maybe just focusing on exports. if you're seeing changes in customer behavior. Jeremy, I know you mentioned seeing new customers show up. Curious if that applies to exports here. And how are you thinking about flows to Corpus versus Houston into the back half of '26?

So yes, we are seeing different customers be interested instead of being spot purchasers or under term contracts only from the Middle East to look to expand where they purchase barrels for some level of security of supply. So that is a different behavior than we've seen. I think you've seen it across commodities as well. So we're going to continue to look at that as ability to term up additional space. Corpus versus Houston, look, both are very good markets.

The Corpus market does demand a premium. It's a single quality barrel that's WTI largely [ some TL. ] Houston has got a broader mix of what gets exported. It's got more refining capacity. They're both very good markets. Both markets are largely tight. You've got close to 90% utilization in both markets. So we're cautiously optimistic that both will continue to grow as the markets tighten and get to back where you're closer to the longer-term margins where we'll contract additional space.

Spiro, this is Willie. You know our assets well, but I think the thing I wanted to highlight is on our visits with people, we've been talking about the market shifting to a demand pull model. We've been in a supply push model for quite some time with surplus supply in the world. I do think what you're -- the question that you're asking is really hitting on a key thing, which we believe is happening. With the inventorying of the global inventory of the crude supplies, this is really shifting to a demand pull market. And your question about others wanting to come and get access to barrels really as a security of supply is very true.

And if you look back in the second quarter, we actually had record crude exports out of the Gulf Coast. And as these things typically work because you've got a long supply chain with ships, that shifted. And now we had more volumes going up to Cushing, but that could easily start shifting back as global events happen. So the key thing for us is we've got great assets that can play all these different options. Hard to exactly figure out what will happen, but when it will happen, we feel we'll be in the right place in time to be able to capture it.

Our next question comes from Keith Stanley with Wolfe Research.

Only one question for me. I wanted to dig into the Cactus III economics a little more. So your Permian CapEx this year is only up $35 million. You have the $40 million earn-out. So it kind of implies the Cactus III project is, call it, $50 million to $75 million, which would be a really high return for you guys. So looking forward, how can we think about the cost of future phases of expansion of Cactus III? Do they get a lot more expensive than this? Or can you replicate this a few more times?

Keith, it's Chris Chandler. I'll take that. First, let's talk about the phase we just completed 75,000 barrels a day. Without sharing the exact number, I think you're reading into our numbers well in that -- the expansion we just completed was highly economic. We were able to do it for far less than we anticipated when we acquired the asset, able to do it more quickly. I would think of it in terms of tens of millions of dollars, and that doesn't include the earn-out that we disclosed in the slide. So very, very economic and very quick to market, as Jeremy shared.

We're taking a close look at future expansion opportunities. Those will have to be backed by customer commitments, of course. But I think it's safe to say that the costs for those future phases are looking more economic than we originally premised as well when we acquired the asset. So we're really pleased overall, we've been able to capture the synergies with Cactus III and expansion opportunities are ready to go and look very economic when the customer support is firmed up.

Our next question comes from A.J. O'Donnell with TPH.

Maybe if I could just follow on to the last question a little bit. Could you talk a little bit more about just kind of the economics of the expansion? Just thinking -- I believe you said the affiliate could fill the space right now. But as you work to contract that over the longer term, where do you kind of see the rates on that project falling? That's largely where they are at right now? Or does that get a premium?

Good question. It depends on how we contract that. If it's with the shippers that we have in the past, it's going to look just like the rates we disclosed last year and the year before when we did our recontracting efforts. So the long-term rates are in that ballpark, and we'll continue to look there. If we opportunistically find other markets, we will -- it all depends on the structure of the term and everything else. So we don't necessarily want to give away our playbook on the earnings call. But I would say, long term, expect it to be consistent with where we have been executing.

Okay. Great. And then just one more on Cactus III. I think in February, you kind of described stabilizing the base pipeline, then looking at capital efficient expansions. And then in May, you said an expansion would kind of be phased and paced to demand. And now that the first 75 is sanctioned, is the base pipeline fully recontracted and stabilized? And how soon could we expect to see additional phases?

Good question. So the duration of the next phases will be longer than this one. So I think it will take some time for the next phases. But as far as the base contract, we have sufficient demand right now to contract the pipeline, the expansion and the other, it's a matter of price. So I think we see sufficient demand to contract the base pipeline. As far as future expansions, they will take time to come up.

And A.J., this is Willie. I think a lot of that really depends on my earlier comments about how many -- how much people need the barrels back to that demand pull, right? We're talking -- what Jeremy is talking about is it's basically ideally a longer-term contract. It's the tenor versus the price, and that's going to evolve. And at some point, we think it's going to continue to be scarce, and that's why we're pretty constructive with the market going forward, including the export markets.

Our next question comes from Jackie Koletas with Goldman Sachs.

Just thought I'd follow up on a question quickly. You reiterated your confidence in capturing that the $50 million of cost efficiencies by the end of this year and then another in 2027. Can you just provide us a progress update here on where these savings are physically materializing? And what could drive incremental efficiencies from here?

Jackie, it's Chris Chandler. Yes, we've made good progress on our commitment to capture $50 million in 2026 of efficiencies. Certainly, the NGL sale was a catalyst in that area, but not by any means the entire driver. We've made a number of changes that contribute to that $50 million and an additional $50 million that we expect to capture in 2027. But I think in terms of reassessing and streamlining our organizational structure, looking at the number of employees we have in leadership and management roles. We're more focused and crude oil pure-play company. So that demands a different level of oversight and a different approach to how we run the business and our business processes.

We've done some targeted rightsizing of our trucking business, closed and consolidated some marketing offices and just taking a fresh look at everything we do and how we do it from a business process standpoint. So as to capture year-to-date, it's fair to say we've realized a little less than half of the $50 million so far this year and we're on track to capture the remaining by year-end 2026. And again, we feel good about capturing an additional $50 million in 2027. I hope that helps.

No, very helpful. I appreciate it. And then just a follow-up on the Canadian gathering system. Just thought you could talk a little bit more about the moving pieces are overall, the incremental Canadian egress and a little bit more color on what you're thinking about the timing there and then potential size capacity on Rangeland.

Good question. So I think from our standpoint, think of Rangeland as a gathering system. And so the expansions there are filling latent capacity. The Rainbow is an expansion of capacity of the mainline and building laterals. As far as egress goes, first, we'll look to fill our existing, which we do on [indiscernible] in Rangeland today. I think there are some other more capital-efficient projects that will probably go. It may be something that we work with those counterparties on opportunities, like I said, around Capline and Cushing and other locations. I wouldn't -- I don't think the Rangeland expansion would be competitive with some of those projects based on scale.

Our next question comes from Gabe Daoud with Truist.

I was hoping to maybe just ask another Permian macro question. Any views just given conversations with producers now for '27, any views on where the rig count could go from here? And then just trying to frame when you think there could be an acceleration in crude volumes at a basin level, maybe approaching 8 million barrels per day? Because I think that's probably what the basin hits by 2030. But if crude remains elevated, I'd imagine you could maybe see some acceleration. So curious maybe what your overall views are on that.

So first of all, the gas egress has come on quicker than we expected. And with that, as you've seen with the G&P operators, their plants are filling up quickly. The same is occurring. So the 100 to 200, we are seeing volume from July into August that trends probably favorably to those numbers. So we could see it go -- we have a positive bias based on the last few weeks. So from our standpoint, as Willie mentioned, positive momentum going into 2027. Look, Willie mentioned that you have to give us a price, you have to give us the economic background, but productivity has improved.

So the 260 rigs you see today are more efficient than the 260 rigs you saw in 2025. So we're excited about the opportunity to grow through the second half of this year and into next year. And it's just a matter of the duration of that as to where the basin gets to. So you see a very favorable path to get to north of 7 million barrels a day, continued improvements on recoveries reducing breakeven prices and supportive commodity prices will be required to get to 8 million barrels a day, but it's not an unreasonable scenario. We're just -- like Willie said, you got to tell us the backdrop and tell us where the basin gets to.

Gabe, it's Willie. You've heard many of the other calls. And as I look at the transcripts and the summaries of them, there are a number of the producers that have really touted the ability to produce more. So that's good, right? We want to be able to -- we want our industry to produce at the most efficient and economic point, and I think people are starting to crack the code on that.

No, that's right, Willie. A lot of operators have highlighted surfactants and other technologies to improve productivity and recovery factors. So that could also be a tailwind, as you noted. Maybe just a quick follow-up. So in the conversations, is there a specific price for '27 where you feel operators could be a bit more active? I see [ 70 ] on the screen now for '27. Is it[ 75 ] get folks more excited? Just curious from your conversations if there's a signal that seems like pretty obvious as to where producers could add.

I'll let Jeremy forecast the price.

Less about price, but more about activity. So your first question was where could you see incremental activity. I think you've heard a number of operators talk about deeper benches in the Midland Basin being very productive. And I think you'll continue to see capital move into those. In the Delaware Basin, New Mexico continues to expand in all directions.

Vertically, they keep going to find other benches. And then horizontally, it keeps going north and to the West. And so from our standpoint, New Mexico continues to expand and surprise to the upside. You're even seeing some of the deeper benches work in areas like the Woodford and Barnett and the Delaware Basin in certain areas. So I think the basin continues to expand its resource base, and we're excited about that because it sits under our footprint.

Our next question comes from Theresa Chen with Barclays.

Willie, going back to your comments about your organization's ability to capture tailwinds from this macro environment and some of, I think, Jeremy's comments to earlier questions. Just looking at the past several months of heightened market volatility, has anything about the performance of your commercial organization exceeded your expectations? Are there specific examples where the team was able to capitalize on market dislocations or emerging opportunities in ways that surprised you?

Theresa, one, it's good to hear your voice. The answer is there's a lot of -- we've got a good team that captures different opportunities. And while not getting into all of the different strategies we've had, I would point to the response and being able to get barrels down to the Gulf Coast. We had record exports during the second quarter. We were able to basically source barrels and help facilitate moving those. So that volume -- that's one of our strategies. We've been able to capture some volumes or values around the shape of the forward curve that has been good.

And the other piece of value that always comes, it's not the market opportunities, but it's the discussions that we have with our producer partners on where their pinch points are that set up for some of these capital projects that we are now putting into place. Oil price level itself, we stand to gain on PLA. I think as Al shared, we've got a little bit of PLA left to hedge. We've captured -- we hedged a good portion of that going into this year, and so we didn't have a lot much to play with, but we still have some barrels out there that could help us for the rest of the year. Hopefully, that helps you.

It does. And in terms of capturing marketing-related earnings related to wide quality differentials, clearly, there are a lot of variables at play here. Specifically, how do you think about the growing volume of Venezuelan barrels in the Gulf Coast, increasing heavy supply in PADD III, coupled with incremental Westbound egress for [ WCS ] over time, whether that be a [ TMX ] expansion or 1 million barrel per day West Coast oil pipeline, how does that change your views on heavy differentials across North America and your marketing and optimization opportunities there as a result?

Theresa, good question. It's a very dynamic question. The pace of growth in Canada and the pace of growth in Venezuela will dictate that, right? And if you pull the Saudi barrels out of the Gulf Coast and you have more Venezuela coming in, maybe that's somewhat of a dislocation. But realistically, as Venezuela pushes in, it pushes Canadian back and widens those differentials a bit and there are spreads with heavy differentials across grades, but the West Coast could add egress. So it's a function of how quickly is egress added in Canada, how quickly does Venezuela production get to the Gulf Coast and can it grow on a sustained basis versus production.

So you have those 3 things dictating it, and they're all moving at different speeds. And so any time there's a dislocation, our team can capture it, but our preference is first to move it. So we'll look to move barrels. And if there's dislocations that we can capture, we will. So I think from our standpoint, growth is good, dislocations are good, and we'll help our customers get around those dislocations.

And Theresa, this is Bill -- on the Venezuela question, if it was around our views on heavy barrels coming into the Gulf Coast, I think it's healthy because those barrels are originally designed for the Gulf Coast, and that pushes barrels back, which allows us to have more opportunities with that.

Our next question comes from Sunil Sibal with Seaport Global.

So first of all, just a clarification. I think Al mentioned that in Q2, you had $14 million of environmental remediation expense. I was curious, is there any impact of that in the second half also in terms of your efforts on that front?

This is Al. No, they were one-off. We do not expect that to recur in the second half.

Okay. Then obviously, a lot of discussion on today's call on Permian as well as Canadian opportunities. I was curious, as you think about the $400 million to $450 million of CapEx spend that you CapEx spend that you incurring forward here, are there other regions or any specific regions where you see outsized opportunities?

Sunil, this is Willie. The better chance to get higher returns are around our assets. And while we don't target assets only by region, if we've got strong returns anywhere along our value chain, we consider it. But the chances are it's going to be in the areas that have more activity. But we remain very, very disciplined on our thresholds, and it's more return-driven and strategy driven than region driven.

Okay. So you're implying, Willie here, that $400 million to $450 million, it's -- you can basically get through that in those 2 regions primarily, right?

That would be a good assumption.

I'm showing no further questions at this time. I would now like to turn it back to Willie Chiang for closing remarks.

Thanks, Daniel, and thanks, everyone, for joining us today. We look forward and are excited to see you on the road. Take care, and have a safe weekend.

This concludes today's conference call. Thank you for participating. You may now disconnect.

Good day, and welcome to the PAA and PAGP First Quarter 2026 Earnings Call. [Operator Instructions] Please note this call is being recorded. I would now like to turn the call over to Blake Fernandez, Vice President of Investor Relations. Please go ahead.

Thank you, Michelle. Good morning, and welcome to Plains All American First Quarter 2026 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, CEO and President; and Al Swanson, Executive Vice President and CFO, along with other members of our management team.

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

Thank you, Blake. Good morning, everyone, and thank you for joining us. This morning, we reported first quarter adjusted EBITDA table to Plains of $730 million. Al will cover the details on our results in his portion of the call. Let me start with the macro environment, which has changed significantly since our last call. Recent geopolitical events have reiterated the importance of reliable, secure and responsibly produced energy.

The closure of the Strait of Hormuz has significantly disrupted global shipping channels and Middle East supply, contributing to stronger commodity prices over the past couple of months. In response, excess floating storage has been drawn down and strategic petroleum reserves are being released globally. While this helps balance the market deficit on a short-term basis, we are seeing a more constructive oil market developing on a longer-term basis.

We expect this destocking environment to continue over the next number of months and ultimately drive a restocking phenomenon longer term, longer term as countries replenish depleted strategic petroleum reserves globally. Post war, we would not be surprised to see several countries restock their SPRs above pre-war levels, essentially creating an additional layer of demand into the future, which should support prices and incent producer activity.

On the supply side, OPEC production capacity post war remains uncertain, but we suspect spare capacity will be tighter based on a slower recovery of shut-in production and infrastructure damage during the war. We believe the conflict shifts the focus towards more geopolitically stable regions to ensure security of supply.

Against this backdrop, North America, including the Permian, remain well positioned to play a critical role in meeting global demand. As this occurs, the value of existing infrastructure in the ground should continue to increase over time. For these reasons, we believe Plains is well positioned for both the near-term volatility and longer-term macro environment.

Based on these market dynamics and the growth trajectory that we see for our business, we have increased our initial 2026 EBITDA guidance. As highlighted on Slide 4, we're increasing the midpoint of our full year 2026 adjusted EBITDA guidance by $130 million to $2.88 billion. The NGL segment EBITDA is now expected to be $170 million this year, following first quarter outperformance of $45 million and the updated divestiture timing now in May 2026.

Our trajectory of growth this year is underpinned by 3 key drivers: the sale of our NGL assets, Cactus III synergy capture and streamlining. The growth of our EBITDA is paced with the execution of these initiatives and is enhanced by capturing optimization opportunities that have been substantially secured over the next 3 quarters.

We're also seeing increased producer interest in both Canada and the U.S. for additional connections to our system. The combination of all these factors will ramp up through the year and position us well into the future. Our premier crude oil footprint continues to support stable fee-based cash flows in a variety of macro backdrops.

As global markets turn to North America for long-term energy supply, we are well positioned across key producing basins and downstream markets to drive multiyear growth. We remain committed to our efficient growth strategy, generating significant free cash flow, optimizing our assets, maintaining a flexible balance sheet and continuing to return 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. Slides 5 and 6 contain adjusted EBITDA walks that provide additional details on our performance. For the first quarter, we reported crude oil segment adjusted EBITDA of $582 million, which was broadly in line with our internal estimate and includes a full quarter contribution from the Cactus III acquisition, offset by a number of one-off items, including winter weather impacts in the Permian, system maintenance and timing of minimum volume commitments.

Moving to the NGL segment. We reported adjusted EBITDA of $145 million, reflecting a stronger-than-expected contribution from higher straddle production and improving frac spreads in March. A summary of 2026 guidance and key assumptions are on Slide 7. Growth capital remains $350 million, while maintenance capital was increased to $185 million, reflecting ownership of the NGL assets in May.

Regarding the $130 million increase in EBITDA guidance, key drivers are outlined in the waterfall on Slide 8. The NGL segment increased by $70 million, driven by outperformance in the first quarter, along with the ownership of NGL assets in May. The oil segment was increased by $60 million, driven by captured optimization opportunities, FERC tariff escalators, increased spot tariff volumes and increased West Coast volumes.

To the extent that elevated commodity environment persists in the second half of the year, we would expect to capture incremental opportunities. For 2026 guidance, we continue to assume Permian crude oil production to be relatively flat year-over-year. While we have yet to see a meaningful shift in U.S. producer behavior, any increase in activity would likely benefit 2027 and beyond.

We expect an improving back end of the crude oil curve and removal of natural gas takeaway constraints as new egress projects start up later this year to drive incremental activity throughout the year. As illustrated on Slide 9, 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 $1.85 billion of adjusted free cash flow, excluding changes in assets and liabilities and excluding sales proceeds from the NGL divestiture. Our pro forma leverage at the end of the first quarter was 4.1x, reflecting the Cactus III acquisition.

First quarter leverage pro forma for the NGL sale would decrease to approximately 3.5x, and we would expect leverage to migrate towards the low end of our target range of 3.25x to 3.75x by the end of the year. We expect net proceeds from the NGL sale to be approximately $3.3 billion, which is approximately $100 million higher than our prior estimate.

Our acquisition of Cactus III last year has mitigated the tax liability to unitholders resulting from the NGL divestiture. As a result, we no longer expect to pay a special distribution following the closing of the NGL sale. Before handing it back to Willie, I would note that both current and deferred taxes are elevated on the statement of operations this quarter because of the restructuring activities associated with the NGL sale.

There was no cash tax impact in the quarter as payment of the related taxes will be made in conjunction with closing or in future periods. With that, I will turn the call back to Willie.

Thanks, Al. In the midst of volatile energy markets, we remain steadfast and focused on executing our 3 initiatives for 2026, closing the NGL sale, driving synergies on Cactus III and advancing our streamlining initiatives. Our efficient growth strategy has positioned us well to execute through a range of market environments, generating durable cash flow and creating long-term value.

Importantly, the improving oil macro environment starting to present additional organic investment opportunities with strong returns. We continue to evaluate both organic and inorganic opportunities in a disciplined manner. Capital investments help underpin long-term EBITDA growth, but they must meet our return thresholds and provide visibility into future return of capital to unitholders.

Our transition to a pure-play crude midstream company, coupled with the acquisition of Cactus III is proving timely as tensions in the Middle East position North America as a key source of global energy supply into the future.

Before I turn the call over to Blake, I'd like to make a brief comment about our pending transaction with Keyera. In terms of timing, as reported by both Keyera and Plains in separate releases earlier this week, we're targeting to close the transaction this month. While it's unfortunate that the Competition Bureau has chosen to challenge the transaction, their lawsuit does not prevent the parties from closing the transaction, which both Plains and Keyera are committing to do so.

So I realize you have -- you may have some additional questions, but I hope you understand it would be inappropriate for us to comment any further on this matter. So we would appreciate if you would refrain from asking questions regarding the transaction.

Blake, I'm now going to turn it over to you to lead us through Q&A.

Thanks, Willie. As we enter the Q&A session, please limit yourself to questions will allow us to address as many questions as possible from participants in our available time this morning. With that, Michelle, we're ready for questions.

[Operator Instructions] Our first question comes from Brandon Bingham with Scotiabank.

Just wanted to maybe ask on the new guide. If I look at your sensitivity and the new crude price expectations, it would imply that at least on price movements alone, the crude contribution should probably be higher than what is currently shown. Could you just walk us through what's baked into the new guide and maybe the embedded outlook in there?

Sure. Brandon, this is Al. Yes, our original guidance for the year assumed a $60 and $65 environment for 2026 to kind of a $62. We came into the year highly hedged at roughly those levels. The $85 environment that we're talking about for the future is roughly the strip from June through December when we looked at it. So there would be some benefit based on crude prices on our PLA, but the fact that we had hedged quite a bit before entering the year, that sensitivity we give is just a raw sensitivity.

In order to make it more meaningful, we would have had to have disclosed to you the hedge position at the beginning of the year, which we haven't historically done. So what I would say is that the first quarter performance and the 9 months of our guide is very minimally impacted by actual PLA pricing.

Okay. Yes, very helpful. And then maybe just wanted to ask about in light of some of the commentary in your prepared remarks about a more constructive longer-term market and just the whole macro environment as it stands today, how are you guys thinking about the potential for the Epic expansion at this point?

Brandon, this is Jeremy. We're excited about the opportunities around our entire long-haul portfolio and are having constructive dialogue with existing customers and new customers looking for secure supply from the United States. So that results in some spot activity. But longer term, the expectation is to contract at higher rates than maybe before this would happen with potentially new counterparties.

So that would apply to recontracting existing pipeline capacity and expansions as well. So we're looking at all the above and hope to have updates in the coming quarters on how that looks.

Our next question comes from Gabriel Moreen with Mizuho.

Maybe I'll just ask the Permian macro question, really, in terms of sort of your best outlook. I think previous years, you had talked about 200,000 barrels a day year-over-year growth. Best venture at this point, I realize there's a lot of things in play and things are changing quickly. But do you think that goes significantly higher from here, $400,000, $500,000 in '27? I'm just curious what your latest thoughts are there.

Yes, Gabe, this is Willie. Jeremy may have some additional comments, but I'll give you my thoughts. The U.S. producers have remained very disciplined as far as capital allocation, and they're looking really at the back end of the curve to see where it goes. WTI is roughly $70. And our view is when you start getting into the $75 and above, increased activity happens.

There's also some other things that on the short-term operating bias that's limiting production or constraining it a bit. We've got some natural gas. The Permian has some natural gas takeaway constraints. There are new lines that are being built and being commissioned as early as later this year.

So the thought being that alleviates itself. Our assumption for the Permian this year was flat. And if it -- if there is some upside, obviously, we benefit from it. But our view going forward is not giving a formal guide, but we would expect growth going forward and probably some momentum of volumes behind that's going to increase production here maybe with a little bit of a flush later this year or early next year.

So I think it really depends on the back of the curve, but the systems are ready to go.

And then maybe if I can ask kind of on the sustainability of some of the marketing opportunities you're currently seeing. Can you just talk about, I guess, some of the spreads that you're seeing and also on the value of dock space the extent you're debating internally maybe terming some of those out at higher prices?

And then also the steepness of the curve in backwardation, how that's playing with your storage? Is that helpful? Is that a hindrance? I'm just curious your thoughts on that.

Gabe, without getting into specific strategies, which I would say time location, quality spreads, all that volatility, we benefit from all of those because we have the assets, the supply position and the trading function to capture those opportunities.

While it's hard to forecast those when they arrive, and that could be the time spreads, could you sell a barrel now and buy it back later by emptying a tank, that type of thing. Could you -- difference in grades between Canada and the United States, difference in grades on Gulf Coast grades, all of those are strategies and things we can take advantage of with our integrated system. And so we're excited about those opportunities.

What we've put in this as Willie and Al both stated, we've substantially captured what's in this forecast. It's hard -- this is a very volatile time period. We've only been in the 60 to 70 days. So it's hard to forecast that to continue. But if it continues, we would expect to capture more opportunities going forward.

And just to add on to what Willie is saying, we do estimate there's close to 200,000 to 300,000 barrels a day of oil that's behind pipe in the Permian Basin. So that flush production he's talking about is substantial. And a lot of that's in the more constrained areas of the Delaware Basin, which we have a broader footprint.

So take New Mexico and other places. So as Willie said, we're not giving a formal guide, but that -- if you look at the plot of -- you talked about spreads, the Waha Spread, it's almost flat price in Waha has been largely negative since last September. That's what's accumulating all of this to go.

And so as gas prices recover, productive capacity is already there to add. And as you add more, that puts more pressure on potentially long-haul spreads and the ability to term up contract at greater rates. So we're seeing more demand from new customers. We're seeing potentially less production. Those should all benefit to taking short-term opportunities and convert them to longer-term opportunities.

And Gabe, this is Willie again. If you look at our numbers, long haul has increased and the margins on that has also improved. So I think we're moving to a more structurally full life situation as we go forward, which should be constructive for us.

Our next question comes from Manav Gupta with UBS.

I just wanted to focus a little bit on the weather impact. I think it was about $49 million quarter-over-quarter. I'm just trying to understand the fair timing of minimum volume commitments. Is there a possibility some of this can be reversed in 2Q? Some of what you lost in your -- in the current quarter comes back into the second quarter. If you could talk a little bit about that.

Yes, Manav, those are 2 different things. But first, with regard to weather, weather is just production shut in for a period, you can't make that back, but the flush production does come back. With regard to the timing of MVCs, that's continuous in our process. And if you look at some of the earnings calls from others about their dock performance or other things in that first quarter, freight was really expensive and margins didn't have people moving.

So long-haul volumes were down across the industry, but that has completely reversed in timing. So you would absolutely expect that to be recovered. It's just a question of when those MVCs accrue versus when they're paid, but all the pipelines are full again and the MVCs are being reversed.

Manav, this is Willie. If you're referring to Slide 5, I think the point of your question is on that negative 49, there's a bunch of onetime events in there that you're absolutely correct that we -- that will not occur again as we go forward.

Perfect. And if you could also talk about the very strong results from the NGL segment in the first quarter versus the last quarter, some of the drivers of what helped you deliver a much stronger earnings on that segment quarter-over-quarter.

Sure, Manav. This is Jeremy again. higher border flows than expected. You had very full storage in Canada and continued production, which required the volumes to be exported, and those were exported through our Empress assets. So higher border flows leads to more straddle production, and that would all be unhedged and impact -- so that was more border flow concept, but higher frac spreads as well in the first quarter towards the end of the first quarter.

So I'd say those 2, and that has continued into the second quarter, which is the increase in guide for the NGL business through closing.

Our next question comes from Michael Blum with Wells Fargo.

My question is really on the guidance, the crude oil segment. So I'll just ask it all at once. So the increase, I just wanted to make sure I understood, it sounds like most of this is optimization, which you've already locked in and then maybe the rest is PLA. So I just want to make sure I understood that. And then the second part is, if prices stay elevated for the balance of the year, would there be upside to the guide in the crude segment? Or is that already sort of baked into the numbers?

Michael, this is Willie. Great question. Our assumptions are -- the numbers that are in there really are what we've captured that roll off through the year that we'll actualize on optimization efforts. And you're correct. If we have a stronger macro environment, higher prices, there definitely is upside.

Our next question comes from Jeremy Tonet with JPMorgan Securities.

Just wanted to see what you guys are seeing locally ear to the ground there as far as producer activity and whether rigs being picked up by the independents or how -- if larger drillers could as well? And what would be needed to be seen, I guess, across the strip to gain the comfort to do that. And so just wondering how you think production could uptick here? Or what do you see?

Jeremy, this is Jeremy. So since it started, you've already seen 15 rigs added back, and we would expect some to continue. But as Willie mentioned, there's a bit of a throttle right now. You can't add more natural gas to the system. as the flaring not allow. So productive capacity is there, rigs being added now would impact 2027. I think there's a bit of confusion by the market in that if you take the products market and the physical crude market, they're substantially more tighter than the financial markets would indicate, which means the back end of the curve has to come up.

It's very difficult even if you open the Strait of Hormuz tomorrow to get everything back in order the way it was. It's going to take a while for shipping to start. You have to empty tanks before you can start back up production. Products markets are just empty in some places. So I think there's real dislocation that will take time.

I think some of the integrators have stated it's for every day, it's down, it's 3 days to get back up. And so it's potential for months to get out of this, even if they were resolved today. I think that's the part that probably producers are waiting on is more surety at the back end of the curve that they bring rigs on because at this point, the service companies are stacked equipment.

It takes capital to get those back in, takes commitments to make those back in. So I think producers to make those commitments need commitment from prices that they'll be there. And the longer this goes, the more likely that will occur.

But I think it's just a dislocation in the back end of the curve right now that's maybe causing some hesitancy, but that's going to prolong the problem.

Got it. That's helpful there. And then I just want to see, I guess, how you think that impacts basis over time here and what it could mean for future egress expansion?

Thanks, Jeremy. It's constructive for basis, more production is and more demand on the water. So you're seeing a specific to the Corpus market and some of the on-the-water efficient docks, you're seeing higher pricing and relative to even the screens. And so that on a prolonged basis as there's new buyers coming to America, there's vessels that used to be pointed at other locations that intend to come back and forth to the United States for a while.

So I think you're seeing that on the NGL side. I think you'll see it on the LNG side, and I think you'll see it on the crude side. More buyers and more demand is generally constructive for spreads. And so we would expect to match either our supplier or our customers with that and hopefully offer service at a higher rate.

Jeremy, this is Willie. You're aware that on Cactus III, we have expansion capacity there. And as we've always said, we're going to pace that with market demand and commercial contracts. The other highlight on that is, as we've gotten to know the project and have assessed it, we have the ability to do that in a phased approach.

And also, it's really fairly flexible for us to get additional volumes, and it's not a long term -- it's not a binary big expansion. There's ways to do it in phases, which should match customer demand. And generally speaking, in a higher price environment, there are more opportunities because there's basically a pull on the whole system.

And so typically, in that kind of a market, the market opportunities and optimization opportunities become a little more prevalent versus a lower price where less is moving and there's less opportunities. I hope that helps.

Our next question comes from Jackie Koletas with Goldman Sachs.

First, I was wondering if you could just comment on the progress of your cost reduction initiatives. Are these on track with expectations at this point? And is there any potential for upside capture here? When should we expect for Plains to realize more significant efficiencies through the year?

Jackie, it's Chris Chandler. I'm happy to take that. We are on track to capture the efficiencies, $50 million by the end of 2026 and an additional $50 million in 2027. We've actually already made a number of changes, some unrelated to the NGL transaction, some in anticipation of the NGL transaction. So we feel confident in the number. There's always upside.

We're always looking for additional opportunities, and we will certainly pursue any that we find. We're not prepared at this time to change the $100 million target we have through the end of 2027. But on track there, and things are going well.

Great to hear. And then I'll just one on just shifting to capital allocation. With debt reduction as a near-term focus, particularly following the pending NGL sale, when can we expect a shift or kind of allow a shift from debt paydown to a larger focus on potential buybacks or preferred paydowns?

This is Al. I'll take a shot at it. Yes. So clearly, with the proceeds from NGL, we anticipate taking that and paying down roughly a little over $3 billion of debt, which would be the term loan, the outstanding CP we have and a $750 million note that matures later this year. Post that, we expect to be right at the midpoint of our leverage. We expect of 3.5x.

We expect that to migrate down, which will then come back to where we've been for the last number of years prior to the Epic acquisition, leverage towards the low end of our range. Our view would be capital allocation, first and foremost, focused on maintaining distribution growth, funding investments, whether they're organic or M&A related.

As well as looking at taking out prefs should leverage remain at or below the bottom end of the range and opportunistic share repurchases. So a long-winded way of saying that once we get through the NGL sale and deployment of the proceeds back to where we've been operating for the last several years.

I'm showing no further questions at this time. I'd like to turn the call back over to Willie Chiang, President, CEO and Chairman, for closing remarks.

Michelle, thanks. We appreciate everyone's support and attention, and we look forward to seeing you on the road. Stay safe. Thank you very much.

Thank you for your participation. You may now disconnect. Everyone, have a great day.

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 Lana 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 plans 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 transactions or 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 plans 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 3 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 planes at the midpoint plus or minus $75 million with an oil segment EBITDA midpoint of $2.64 billion net to planes, 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 2016 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 and underpinned by a 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 available on February 13 for both PAA and PAGP.

On an annualized basis, the -- 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 walk that provide additional details on our performance. For the fourth quarter, we reported Crude Oil segment adjusted EBITDA of $611 million which includes 2 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 adjusted EBITDA of $122 million, reflecting a seasonal uptick that was moderated somewhat by warm weather [Audio Gap]

Since it's 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're ready to open up the call, please.

[Operator Instructions] Our first question will come from the line of Manav Gupta from 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 cattery without actually putting more pipe in the ground, if you could talk about some of those factors?

Manav, it's Jeremy. 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 said 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 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 and increments that make sense to grow with the basin.

Manav, this is Willie. I think 1 key point that Jeremy highlighted is it's not a binary expansion at 1 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 level.

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] our next question is from the line of Brandon Bingham from 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?

Brandon, this is Jeremy. 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 of 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, 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 discussions 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 and constrained removal. So 1 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 are 2 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.

Our next question comes from the line of Michael Blum from 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 take a 1 pier 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.

Willie -- this is Willie, Michael. When you think about how we came up with the $160 million, right? That was in November of 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, it's still a conservative approach to distribution. And for us, it sets a nice balance for us as we look forward ability to -- for multiyear distribution growth. So I would look at it as kind of a reset to the 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.

Got it. 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. One moment for

Our next question will come from the line of Jeremy Tonet from 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.

Jeremy, Jeremy Goebel. How are you? I was calling -- I mean the idea around Venezuela, think of the initial response of 50 million barrels sold into the U.S. 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. [ Points ] 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 1 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 U.S. So there's a lot of need opportunities and you can expect us to stay on track at looking at those with financial discipline.

Next question will come from the line of Keith Stanley from Wolfe Research..

Wanted to ask on coverage. So the release specifically says that the change in threshold to 150% provides a multiyear 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 2 more years? And if that's right, it implies a fair amount of growth since you'd have to stay above that 10% -- so can you just talk to some of the growth drivers you see in the next -- in '27 and '28 that would support that?

Yes, 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 contribution. And as you think about '27 plus, we've got self-help that choose 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 or larger, that 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.

Next question from the line of John McKay from Goldman Sachs.

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

John, it's Jeremy. 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 kind of what you saw in the last week or 2 and kind of where the recovery stands right now?

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

Next question come from the line of Sunil Sibal from 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 to $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.

Okay. 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 million to 5 million barrels for functional right now is adjacent to our existing facility, our net cost is anticipated to be $10 million. It may take us some time to entice the facility. It's got existing operations 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, it was 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.

Next question will come from the line of AJ O'Donnell from TPH.

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

AJ 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.

Our next question will come from the line of Jeremy Tonet from 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 kind of 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. Pushing 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 U.S. 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 and 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.

Good day, and thank you for standing by. Welcome to the PAA and PAGP's Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Blake Fernandez, Vice President of Investor Relations. Please go ahead.

Thank you, Andrea. Good morning, and welcome to Plains All American's Third 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 the call today.

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, CEO and President; and Al Swanson, Executive Vice President and CFO, along with other members of our management team.

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

Thank you, Blake, and good morning, everyone. Thanks for joining us. Earlier this morning, we reported solid third quarter adjusted EBITDA attributable to Plains of $669 million, which Al will cover in more detail. It's an exciting time for Plains as we continue our multiyear strategy of building the premier North American pure-play crude midstream company. Over the past few years, our team has successfully executed on our strategy by meaningfully lowering our leverage profile, maximizing free cash flow and optimizing across our broad system, all while remaining capital disciplined and returning cash to our unitholders through meeting and beating our targeted annual distribution increases.

With the pending sale of our NGL assets expected to close early next year, our portfolio will become even more crude-focused with a more stable and durable cash flow stream. As discussed on our previous calls, the NGL sale is a win-win transaction at an attractive valuation for Plains and our capital allocation priority has been to redeploy those proceeds to a strong return, DCF accretive bolt-ons while staying within our targeted leverage range over the long term.

To that point, we're pleased to announce that we now own and operate 100% of the entity that owns the EPIC Crude pipeline. This past Friday, we closed on the previously announced acquisition of a 55% nonoperated interest in EPIC from Diamondback and Kinetik. And on Monday this week, we signed and closed the acquisition of the remaining 45% operating interest in EPIC Crude Holdings from a portfolio company of Ares private equity funds for approximately $1.3 billion inclusive of approximately $500 million of debt. As part of the 45% transaction, Plains has also agreed to a potential earn-out payment of up to $157 million tied to the sanctioning of potential expansions of the pipeline system by year-end 2028.

The EPIC acquisitions are summarized on Slide 4. These transactions are highly synergistic and very strategic to Plains existing footprint and are expected to generate a mid-teens unlevered return. We anticipate a 2026 adjusted EBITDA multiple of approximately 10x which we expect to improve meaningfully over the next few years. Going forward, we intend to rename the pipeline system, Cactus III, which complements our integrated Cactus long-haul system that we have operated for years. The acquisition of the remaining 45% of EPIC gives us the opportunity to assume operatorship, which accelerates and increases the synergy capture of the full pipeline, including meaningful cost, capital and operational synergies while improving the takeaway flexibility of our crude system to meet customer needs.

Near term, we're poised to benefit from contractual step-ups, reduced operating costs and overhead, quality optimization opportunities and utilizing the broader plans, Permian and Eagle Ford asset base to drive volumes to EPIC crudes downstream assets. Longer term, the potential expansion capacity of the system provide Plains and its customers with additional egress to the U.S. Gulf Coast and will generate strong returns as demand dictates further expansions.

Regarding the divestiture of our NGL business, we're on schedule to complete the transaction by the end of the first quarter 2026. We have received 2 of the 3 required regulatory approvals, U.S. Hart-Scott-Rodino and the Canadian Transportation Act while the approval process for the Canadian Competition Bureau is ongoing. Importantly, the majority of the proceeds to be received upon closing of the divestiture have effectively been redeployed through our acquisition of EPIC, which will result in an accretive and more durable cash flow stream. Due to timing differences between the closing of the transactions, we do anticipate our leverage ratio will temporarily exceed the upper end of our target range until the NGL divestiture is finalized, at which point we expect our leverage ratio to trend towards the midpoint of our target range of 3.5.

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

Thank you, Willie. For the third quarter, we reported Crude Oil segment adjusted EBITDA of $593 million, which benefited from higher volumes and contributions from recently completed bolt-on acquisitions as well as the impact of annual tariff escalation. This was partially offset by certain Permian long-haul contract rates resetting to market in September. Please note that the fourth quarter should serve as a baseline, representing the full impact of lower contract rates out of the Permian.

Moving to the NGL segment, we reported adjusted EBITDA of $70 million which was down sequentially due to lower sales volume tied to temporary downtime on a third-party transmission system as well as the start-up of LNG Canada. Slides 5 and 6 in today's presentation contain adjusted EBITDA walks that provide additional details on our performance. We are narrowing our full year 2025 adjusted EBITDA guidance range to $2.84 billion to $2.89 billion to reflect lower realized crude prices and contributions from our completed acquisition of EPIC. Please note the benefit from EPIC for the remainder of the year is forecast to be approximately $40 million.

A summary of our 2025 guidance metrics and assumptions are located on Slide 7. Overall capital spending remains consistent with our prior forecast. Growth capital spending for the year is expected to be approximately $490 million. The $15 million increase is primarily associated with new lease connects and capital associated with acquisitions, while the 2025 maintenance capital is trending closer to $215 million, representing a $15 million decrease from our last forecast. In September, we issued $1.25 billion of senior unsecured notes consisting of a $700 million due in 2031 at a rate of 4.7% and $550 million due in 2036 at a rate of 5.6%. Proceeds were used to repay the senior notes that matured in October and to partially fund the EPIC acquisitions.

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

Thanks, Al. We've made significant progress on our journey of becoming the premier crude midstream provider over the last several months, and we believe there are significant opportunities to continue to create value for unitholders through initiatives that are within our control. As seen on Slide 8, the combined benefits from bolt-on M&A, synergy capture and streamlining efforts across the broader organization will provide Plains self-help tailwinds through the near-term volatility. As part of our 2026 guidance in February, we intend to share additional details on these initiatives.

Our strategy centers on the view that crude oil remain essential to global energy and society for decades as outlined on Slide 9. And despite near-term volatility, we remain confident in our ability to navigate current market dynamics and we expect improving fundamentals longer term, anchored by continued global energy demand growth, coupled with underinvestment in organic oil supply growth in diminishing OPEC+ spare capacity.

I'll now turn over the call to Blake to help lead us into Q&A.

Thanks, Willie. [Operator Instructions] The IR team is also available after the call to address any additional questions. Andrea, we're ready to open up the call for questions, please.

[Operator Instructions] Our first question comes from Michael Blum with Wells Fargo.

Wanted to ask on the EPIC deal. Can you give us a little more detail on the synergy capture? How much of that is going to be cost savings versus commercial synergies? And where do you see the time line? Will you capture those synergies and then reach that mid-teens return?

Michael, this is Willie. First thing I want to do is I want to complement our team. If you think about these transactions, these are never perfect timing and they're hard to do. And we were able to do the 2 portions, and particularly with the 45% just announced, it gives us the ability to have more control over every question that you asked. I would also refer you to Slide 4. And if you look at the map and you see how integrated it is with the system, I think that helps illustrate the number of ways that we can win.

There are a lot of ways we can do this. There's a lot of cost structure savings. There's overhead savings and a lot of this will be immediate, and we'll be able to capture it in 2026. And if you think about the expansion opportunities, it's not one step change function on expansion because we operate it, we'll be able to dictate partial expansions as we go and whatever market demands will be. So there's a lot of different ways to win, and it's not simply the expansion. And I would tell you, a good portion of it is the cost synergies, capital synergies and integration with our existing systems.

Jeremy, do you have anything to add to that?

No. Just from a timing standpoint, I think Willie hit a lot of it. But just the compression in multiple to next year is step-ups in contract and cost savings. So things that are almost immediate and contractual. Beyond that, that is all the things Willie talked about. So we're very confident in the ability to compress this over time and part synergies, but part expansions and just recognize we sell a substantial amount of barrels at Midland, and we can move those barrels. We have demand from customers to go to the docs, the docs are willing to expand and ready to expand. There's additional markets that we're not connected to in Corpus that we can move barrels from Midland today that we sell into that pipeline.

So as Willie mentioned, we can expand the pipeline system, we can capture cost synergies, there's a lot we can do immediately, and that's contractual. That will compress to the 10x we announced and the compression beyond that, a lot of that's in our control as well.

And remember, Michael, we operate in that quarter, right? Hence, the Cactus III. So it's not that we have to learn new ways of doing business. This really fits hand in glove with our existing system.

Great. Second question, just with your -- the sale of your Canadian NGL business and now this EPIC acquisition, can you just you refresh us on your expectations for capital return and whether this extends the runway now to deliver the outsized distribution growth you've been providing now for a while?

Michael, this is Al. Yes, our view is that we will continue to increase distributions by $0.15 until we hit our targeted coverage. The year where we're transacting here, part of it will depend on when does the NGL sales close. But we expect to continue to grow the company in 2026, 2027 and beyond. Again, once we hit covered -- our target coverage level, we will revert back to a DCF growth concept. But again, we expect to be able to grow again, if you think of the embedded growth in EPIC from today through next year, that's pretty significant. And again, as that multiple kind of compresses from 10% to 15% unlevered, we see significant growth on this asset. So really no change in our approach there.

Michael, this is Willie again. We've got quite a bit to digest here. So I think what you can see is we'll be looking -- we continue to look at a lot of things. But if we were to transact on things, they'd likely be smaller bolt-ons that fit into the system as we've talked before. We've got plenty of things to get accomplished here over the next 6 months.

Next question comes from Keith Stanley with Wolfe Research.

I want to follow up on the distribution question first that Michael just asked. So Al, on your answer, you referenced how there's some noise potentially next year related to the Canadian NGL sales. So to the extent you weren't at the coverage threshold for a $0.15 increase next year because of timing factors related to that sale and redeployment of proceeds, would that impact how you look at the distribution? Or would you see through that and look more at kind of where the run rate DCF would be?

I'll take a shot and Willie jump in. Yes, clearly, we would look through noise to run rate as to how we would think about that. Clearly, if the NGL asset doesn't close early in the year and takes, we'll have more DCF. So some of that noise necessarily wouldn't be a limitation per se. But again, our view would be to look beyond the current year as we evaluate this. Clearly, management and the Board have robust discussions around distributions and what we're expecting to do. And clearly, the first call on that will be early January when we announce our distribution for February.

And Keith, Willie here, you know our coverage target is 160% of DCF to coverage. So that gives us a little bit of flexibility. And as Al said, we always play for the long term. Our focus is return of cash to our unitholders. So I think a lot of that would play into it, and I would agree with everything that Al said.

The second question, going back to EPIC. Can you give some color on the duration of the contracts and how you would characterize rates on that pipeline relative to market? It sounds like 2026, there's somewhat of a recontracting benefit already that gets you to the 10x?

Sure, Keith. This is Jeremy. There's a substantial portion of the pipeline that's contracted for long term, and I believe that was announced in the restructuring last year that EPIC did. The balance of the pipe has medium duration contracts, we feel comfortable in our ability to work with those shippers to either extend those contracts or add new shippers to those contracts. We're just taking over this week, so it would be premature to talk about everything associated with it, but I'd say we like where we sit. The rates are at current market rates, they're not meaningfully above market rates, which means longer term, we expect this to be a stable and growing cash flow profile, which at least to Michael's question earlier about DCF accretion between the sale of the NGL in this business? We think that will be substantially DCF accretive over time the trade of those 2 assets.

And Keith, I might just help. I think publicly and previously, we said the portfolio had a weighted average duration through 2028 with EPIC, this should extend that out to October of '29 in case that's helpful.

Our next question comes from A.J. O'Donnell with TPH.

I just wanted to talk -- go back to EPIC. And now with 3 pipelines in the Permian, Corpus and Christi corridor under your control, how are you thinking about portfolio optimization and maybe like what kind of opportunities there are to move flows across your pipelines and/or reduce operating costs on the 3 assets?

A.J., this is Jeremy. Great question. All of the above, and it all depends on market conditions, right? So as you -- as the pipes get tighter or looser, you're going to do different things. So you can obviously optimize operating costs, variable costs across the pipeline system. You can offer flexibility across the pipeline system between common shippers to access more markets and push barrels into different connections, you can optimize capital across the system, you're going to optimize tankage. There's a lot you can do with -- and Chris' team is going to do a great job and they've been actively involved in the diligence system of the system.

So I think we're very excited with that. We're just scratching the surface. It extends beyond the long-haul business. This is optimizing flows through the POP JV to get to the origins at quality in all those locations as well as in the Eagle Ford. So this touches hundreds of miles across multiple assets for us. So we think there's a lot of ways even on the operating costs aside from the initial cost reductions we'll see to optimize our costs across the system, our quality optimization and connectivity across the system and flexibility for our customers. So the same thing that's allowed us to grow a strong position in the gathering business in the Permian. We can apply all those same things and extend the runway from the gathering business through the long-haul business to the docs, to the markets at Corpus and throughout the Eagle Ford as well.

Okay. Great. Appreciate that detail. Maybe just one more on EPIC and thinking about potential capital requirements to achieve some of these synergies excluding larger projects such as powering the pipeline up to the full design capacity. What kind of additional capital requirements do you see for making these connections either in the Eagle Ford or downstream? Are they relatively small in nature? Or could we potentially see CapEx moving a little bit higher next year beyond the normal range?

AJ, this is Chris Chandler. I'll take that. The short answer is the investments for the activities you talked about are expected to be on the modest side. Our near-term capital spending related to EPIC is certainly going to be directed towards that synergy capture. I think about connecting the systems throughout whether it's at the origin for supply optionality or throughout for our operating and quality optimization. So we see some good opportunities there, but it won't be significant from a capital standpoint. The update to the guidance we gave in for 2025, certainly incorporates what I just mentioned there and our guidance in '26 and beyond, we'll capture that as well, but we don't expect it to be significant.

Our next question comes from Brandon Bingham with Scotiabank.

Just wanted to maybe look into 2026 a little bit, if we could. Operator commentary so far this earnings season seems a little mixed with some guys talking about flat crude and others still blown and going to a certain extent and everything in between. So just wondering what you guys are hearing currently you're seeing from your customer base and how that fits with this year's expected Permian growth. And it also looks like the Permian volumes guide is implying a decent step up in 4Q. So just anything that you guys can comment on as we set up for 2026?

Brandon, let me start with that. For the reasons that you described, it's really hard to get a good gauge on 2026. My observations have been, you've got 2 of the large majors that are very, very steady and continuing to grow. There's others that have taken the stop light approach and maybe a little more hesitant. I think it's a very difficult call on where oil prices are near term. Longer term, we're very bullish. The Permian, we're very bullish. Canada, we're very bullish on North American oil growth. But I think there's a lot of signals that have to play out through that.

We've been -- if you think about where our portfolio is, I made a comment in my -- in the prepared comments, you think about global demand continuing to grow, which I do believe that it will because it's going to be -- we need oil for all the different reasons that we all know to create quality of life. But the thing that I've been watching for quite some time is drill bit or organic investment. And if you look at the trends, these are not my numbers, but other people that study this, if you look at the last trend organically, we're not replacing reserves, right? It's below 100%.

And you can't do that for an extended period of time. So that's why we're very, very bullish on North American oil sources. And I think the whole restructuring of the flows of trade from barrels going into the North America to leaving is going to continue. And I would say we're in mid-innings on the efficiency of being able to do that with oil. Certainly, we're doing it not Plains is doing it, but you've got NGLs, you've got gas, all that is an export story, but I think there's a lot of opportunities to win going forward.

But calling 2026 is a really tough one, and that's why we have decided to go to February to be able to give you the best intelligence that we've got. So sorry for the long-winded answer, but hopefully, it lets you know how we feel about it and where we fit in the long-range outlook.

Yes. Very helpful. And then just a quick one. The sales proceeds are effectively utilized now for the most part. So could you just maybe discuss your thoughts on fresh retirement and how it fits into the capital allocation strategy moving forward and just kind of what the pecking order is? I think you discussed a little bit in your prepared remarks, but just any updates there?

Sure. This is Al. Yes, since we announced the sale in June, we've now deployed $3.1 billion via the acquisitions, the BridgeTex acquisition earlier in the year are now $2.9 billion here. So effectively, the proceeds will go to debt reduction. That will allow us to get to roughly the midpoint of our leverage range, shift ahead after closing and reducing debt and being at the midpoint, then we'll go back to our normal capital allocation, which we'll look at -- return cash to shareholders through distribution as well as bolt-on acquisitions, retirement of the [indiscernible] and/or opportunistic common repurchases.

But quite honestly, when you're sitting at the midpoint of the leverage range and still seeing potential opportunities to deploy capital with good returns, we'll be more biased towards looking at the bolt-ons at that point.

Our next question comes from Sunil Sibal with Seaport Global.

So just a quick one for me. Now that you transitioned to a pure-play crude. The DCF coverage ratio of 1.6x. Could you talk about that in terms of how you think about that in more medium to longer term with the new business mix?

Yes, Sunil, this is Willie. The coverage that we said on 160, you'll recall, I think it was late '22 that we announced that. It's something our Board looks at regularly, clearly without the NGL assets and in the more durable cash flow stream that we have, that's something else we can look at, but we still expect to be conservative in our approach. No change to the 160. But as we go forward, the way I would characterize it is we've got a lot more levers that we can work with as we go forward and get a better triangulation of what the future brings.

Okay. And then when you look at your crude portfolio in Permian post the EPIC, could you talk a little bit about your operating leverage in the system vis-a-vis between your gathering and in-basin pipeline and the long haul. Where do you see the most operating leverage?

Sure, Sunil, this is Jeremy. We've been working on contracting. You saw additional volumes on basin through the summer. We've done more contracting there. With the acquisition of BridgeTex with ONEOK, we've worked with them to put more barrels on that system. So we're executing with operating leverage now. So despite the falloff and contractual rates, we're backfilling that using operating leverage. We see a lot of opportunity to do that with EPIC. So that creates a new opportunity for us to use operating leverage in a substantial way, given that the rest of our system is heavily contracted.

And then within the gathering system, there's a few underutilized laterals within the EPIC, we'll work with our POP JV partners to fill those up. So that creates capital avoidance opportunities and the ability to reduce operating expenses through it. So EPIC providing us additional operating leverage in the gathering, intrabasin and the long-haul system for us to then go fill through the long-term contracts we have on the gathering business. So we're excited about the pull-through benefits for the entire system.

Sunil, this is Willie. You didn't asked about the Permian? I might make a broader comment on North America. When you think about the broader macro, there's been a lot of chatter in North America, particularly around Canadian crude, ability to get more Canadian crude to markets. And you're very aware of the expansion that has happened on or the new line of TMX going to the West. Canada has vast resources that could get produced if they are more export routes to markets. And when you think about our system and other systems across North America, one of the challenges are, if you can stitch all that together, there's a lot of ability to get to global markets, primarily by going south to the U.S.

And as you know, we have a large pipeline called Capline that goes from Patoka down to the Gulf Coast that's got a lot of spare capacity to your point on leverage. So we haven't taken our eye off the ball of be able to solve a broader problem of oil that might be in the next inning or even the next inning to be able to get more energy and oil to global markets. And with the footprint we have, we've got a lot of flexibility around that also.

[Operator Instructions] Our next question comes from Jeremy Tonet with JPMorgan Securities.

Just wanted to pick up with thoughts you might be able to share in 2026 and granted, as you said, with the Permian, it's too early to really have much specificity there. But just wondering at a high level outside the Permian for other basins that you're in, if you could provide any kind of high-level thoughts as far as direction of travel in volumes there over time, that would be helpful.

Jeremy, what we've seen this year is a slight decline in the Rockies and Mid-Continent regions across the gathering assets, some in the Eagle Ford as well, modest. We see activity levels being able to sustain that. Some of that was -- you had significant growth in the DJ and Bakken from blowing down drilled uncompleted wells, that's out the system. So we see more stable production in the next year in those regions. And in the Permian, we see maintenance level activity for the short term, but we see significant leverage to increasing that. You've seen it, everybody is reducing capital, but maintaining production. So you can see through this fourth quarter so far in the earnings that efficiencies are there and the ability to drive, we see resource expansion in New Mexico and other locations. So longer term, it's giving us more confidence in the ability to grow the Permian and maintain the other basins at a lower breakeven price. So that gives us some confidence, but that's the near-term look.

Got it. That's helpful. And just a smaller question, if I could, on Keyera sale. How are you guys going about managing FX risk there given the volatility we're seeing in FX?

We fully hedged that basically at the time of the transaction. So we did a deal contingent structure that effectively locked down the rate. And if for some reason the transaction didn't happen, we're not exposed to the adverse movement that could have happened.

Our next question comes from Manav Gupta with UBS.

So a quick follow-up. I think you answered it in a way, but I just wanted to follow up. There are some good deals out there, and you have been very prudent and very smart about these bolt-on deals. So I'm just trying to understand, if there is a good deal out there, which meets all your these criteria, even if you're slightly above the midpoint of your leverage targets, would you hold back or you probably are okay with moving towards the top end and closing on a good opportunity, we think should not be just let go just because you're slightly over the midpoint of leverage. If you could talk a little bit about that.

Yes, Manav, thanks for the question. Well, we always look for opportunities to grow the enterprise value. And I would like to think that our judgment would be good enough to be able to shift through what I would call short-term noise versus long-term noise. And if it was characterized as you did, it was something that met all of our thresholds was strategic with a high risk of being able to execute it, that's something we would absolutely consider.

And a quick follow-up on Keyera, what is the gating item here, if you could -- which needs to be done before the deal can be closed. If you could help us understand that a little better?

Well, I wish I could help you understand it better as I'm not an expert in this, but it's the Canadian Competition Bureau in the process that they go through similar to our FTC HSR process which is ongoing.

Next question comes from Jean Ann Salisbury with Bank of America.

Just one for me. As you're considering whether or not to expand EPIC? Can you give us an update of the relative attractiveness of Houston and to Corpus for export. It seems like over the next few years, there are roll-offs on pipelines to both destinations that would be competing for recontracting. I know Corpus has historically been more desirable, but is that narrowing at all with the Houston Ship Channel expansion?

Jean Ann, this is Jeremy. I would say nothing has materially changed Certainly, both ports are competing. You've seen expansions of Corpus as well. The Ingleside dredging has been done. The channel has largely been dredged. It's way more efficient than it's ever been. So for me, Corpus is getting more and more efficient, even more so than Houston from a large ship standpoint. But the quality differential is a big one, just because it's only Permian barrels touching the docs first, touching a lot of barrels that come from the Mid-Continent. So there's a quality benefit and the logistical benefit and that continues to hold the advantage. That's why you see the premium of it on the water at Corpus versus Houston. And so pricing is also indicating the preference for Corpus over Houston.

Our next question comes from John Mackay with Goldman Sachs.

Willie, I wanted to pick up on your comments around potential involvement on some incremental Canadian crude egress. Could you maybe just talk to us about what some of the moving pieces are? I know you don't have a formal project yet, but would love to hear a little bit more color on maybe what you guys are thinking?

Well, fundamentally, you've got resources that are trapped and you've got -- if you think about the Canadian down to the U.S. Gulf Coast, you've got refiners that want to run that heavy barrel, and you've got different players with different strengths and weaknesses. There are some large long-haul lines out of Canada that could have expansion capacities. Then you get to the border, and there's a number of different options you can get barrels from the border to key hubs, and Patoka is one of them, and you've got a large unutilized capacity at Capline that could ultimately be a solution. That's not to say it's the only solution.

My point on this is really just to reinforce, when we talk about a midstream -- a crude-focused midstream business, this is exactly the things that we are looking at of how we might participate and being able to get low-cost, reliable solutions to additional markets without having to build a brand-new long-haul line from source to destination. Hopefully, that helps, John?

No, that's clear. And the second one will be quick, I think, for Al. Just on the EPIC debt, -- is that -- would you guys just expect to kind of refinance that at some point? Or could that be a, I guess, net use of cash from the Plains side?

Yes. Our plan is -- the base plan was we assumed it. And so it's now ours. And our view was, depending on the timing of these closing and us being owning 100%, which happened obviously on the early track. Our view is to repay it with the proceeds from the NGL sale. So it will be going away. The question is how quickly -- our view will be now that we've closed and depending on how long we think if the NGL transaction doesn't close until maybe later in the first quarter, we might look to do a term loan up at the parent to -- and funnel the proceeds down to repay it earlier. The economics may support doing that. It's a function of how long -- how long the term loan needs to be out. So that's something we'll explore now that we can catch our breath a little bit after getting the thing signed up and closed.

I'm showing no further questions at this time. I'd now like to turn it back to management for closing remarks.

Well, listen, everyone, thanks for joining us this morning. We'll look forward to giving you further updates and seeing you on the road in the near term. Have a great day.

Thank you for your participation in today's conference. This concludes the program. You may now disconnect.