Thank you, Lateef. Good morning.

And welcome to Plains All American first quarter 2024 earnings call. Today’s slide presentation is posted on the Investor Relations website under the News and Events section at 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. Condensed consolidating balance sheet for PAGP and other reference materials are in the appendix.

Today’s call will be hosted by Chairman and CEO, Willie Chiang; Executive Vice President and CFO, Al Swanson; as well as other management members. With that, I will now turn the call over to Willie.

Thank you, Blake. Good morning, everyone, and thank you for joining us.

Our strategy remains consistent and is anchored around capital discipline, generating free cash flow, return of capital to our investors and financial flexibility. And consistent with those themes, earlier this morning we reported first quarter results that are in line with our expectation, which reflects progress towards our full year 2024 targets and provides us with confidence in our ability to deliver on the plan that we laid out in February.

For the first quarter and as illustrated on Slides 3 and 4, we reported adjusted EBITDA attributable to PAA of $718 million and we reaffirmed our 2024 adjusted EBITDA outlook. Al will share additional details on our quarterly performance and the 2024 outlook in his portion of the call.

As noted in our press release this morning and as illustrated on Slide 5, we have increased contract volumes and extended the term on certain contracts such that our weighted average contract duration of our Permian long-haul portfolio is approximately five years, which takes us through 2028. This includes new contracts or extensions on Cactus I, Cactus II, Basin and Sunrise.

This also includes transactions related to 200,000 barrels a day of Cactus I capacity that has been finalized on terms that are consistent with the rates in the range of $1.25 per barrel to $1.50 per barrel that will become effective in September of 2025. Today’s announcement is a win-win for both Plains and our partners and it strikes a good balance between term commitments and maintaining flexibility to capture higher margins from uncontracted long-haul capacity over time.

While we are not providing formal guidance for 2026, we would expect continued underlying growth in the business and contributions from efficient growth investments to offset the lower contracted rates, which results in a broadly flat adjusted EBITDA in 2026 as compared to 2024 guidance for the Crude segment. In summary, we believe these actions should provide greater clarity and confidence in the outlook for our Crude Oil segment and our ability to continue to generate significant free cash flow over multiple years.

Consistent with our efficient growth strategy, and as summarized on Slide 6, Plains acquired an additional 10% in the Saddlehorn Pipeline Company, LLC, and the Mid-Con terminal asset for an aggregate cash consideration of approximately $110 million. These bolt-on acquisitions are expected to generate unlevered returns in line with our return threshold of approximately 300 basis points to 500 basis points above our weighted average cost of capital.

In addition to enhancing our position in both the Rockies and the Mid-Con. With that, I’ll turn the call over to Al.

Thanks, Willie. We reported first quarter adjusted EBITDA net PAA of $718 million.

Slides 10 and 11 in today’s appendix contain blocks that provide details on our first quarter performance. Our outlook for the balance of the year remains essentially unchanged and we are reaffirming our adjusted EBITDA guidance range of $2.625 billion to $2.725 billion for 2024.

We continue to believe the Permian will grow 200,000 barrels a day to 300,000 barrels a day with a back half weighted ramp providing momentum for the remainder of 2024. The NGL segment remains highly hedged with frac spreads at approximately $0.65 per gallon for 2024.

A detailed overview of our 2024 guidance and key assumptions which remain generally consistent with our February guidance are on Slide 12 within today’s appendix. For 2024, we expect to generate $1.55 billion of adjusted free cash flow, excluding changes in assets and liabilities, and including $110 million of bolt-on acquisitions with approximately $1.15 billion to be allocated to common and preferred distributions.

We will also continue to self-fund our targeted $375 million and $230 million of growth and maintenance capital, respectively, net to PAA, which is consistent with our February guidance and includes capital for POP JV well connections and intra-basin improvements, as well as capital related to our previously announced Fort Sask debottleneck project. With that, I’ll turn the call back to Willie.

Thank you, Al. Over the last several years, we have made considerable progress across several initiatives, including running a safe, responsible and reliable business, remaining capital disciplined, generating meaningful free cash flow and increasing the return of capital to our unitholders while maintaining financial flexibility.

Our business model and asset footprint span key supply basins in North America and provides infrastructure solutions to supply global energy demand needs. The combination of our asset base and our strategic initiatives really creates a unique value proposition for our current and potential unit holders, including a double-digit adjusted free cash flow yield and a distribution yield of approximately 7% to 7.5%, with a multiyear targeted annual increase of $0.15 a unit.

We’re pleased to be able to provide the update on our Permian long-haul contracting efforts, which reflects our commitment and focus on being the partner of choice and creating win-win solutions for our customers and partners. Recontracting of our long-haul capacity has been a focal point for investors and we view the developments that we shared with you today as a significant milestone, offering better visibility and clarity around the contractual support for the performance of our Permian long-haul portfolio in the coming years.

The bottomline is we’re well positioned to continue to generate significant free cash flow well into the future. I’ll now turn the call over to Blake to lead us in the Q&A.

Thanks, Willie. As we enter the Q&A session, please limit yourself to one question and one follow-up.

For those with additional questions, please feel free to return to the queue. This will allow us to address questions from as many participants as practical in our available time this morning.

The IR team will also be available to address any additional questions. Lateef, we’re ready to open the call for questions, please.

Good morning, Michael.

Thanks. Good morning.

So, I guess, the first question I wanted to ask was just, I guess, on the guidance, you had a strong Q1, you had the bolt-on acquisition. So, maybe just talk through why not increase the 2024 guidance.

And same line of thinking there, are you -- would you say you’re on track to beat the $0.15 per year of distribution growth, given that it seems like you have the bolt-on, the business is running well? Thanks.

Yeah. Michael, thanks for the question.

This is Willie. It is early in the year.

We’re confident about being in the range and really just don’t want to get too far ahead without seeing a few more things. But we do remain confident of our performance this year.

And I would characterize it as cautiously optimistic that we’ll be able to perform well into the range.

Okay. Understood.

Thank you. And then I wonder if you can comment on the rates for the contract extensions for Cactus II and Sunrise/Basin.

Were those largely consistent with prior rates and just extended the duration or did you also see changes in the rates there? Thanks.

Michael, good morning. This is Jeremy Goebel.

What I’d say on the rates of the Mid-Continent, the reason we were looking to contract those on a long-term rate is it got towards tariff. So, effectively, folks are paying tariff to get there and that’s the right balance for us for long-term rate.

On Cactus II, the extensions were associated with -- contract extensions associated with their options to extend. So, they basically elected their options to extend the existing contracts.

Thank you.

Hi, Tristan.

Tristan, are you on…

Or muted?

Lateef, are you there?

Yeah. Thank you.

Hi, Spiro.

Good morning, everybody. So, maybe I just want to go back to the 2026 comment.

Willie, totally appreciate you’re not giving guidance today, but just kind of want to understand maybe what underwrites some of the view sort of flat over time, just thinking about things like how you think about Basin growth over the next few years and then just other things around M&A. Obviously, you’ve been active on the bolt-on front.

I assume no M&A from here and then also you mentioned some lines of spot upside on some of these open volumes. I imagine that’s all upside to that view as well.

Yeah. Spiro, it’s -- as you well understand, there’s a lot of variables that go into this and it would be -- it would not be a good guidance if we could try to look to 2026 to see all those things, as you know, the tightness in supply and demand on the capacity, operating costs, production.

There’s a lot of things that go into. And while I’m not going to break out everything there, what we were trying to do is as we think about our business in 2026 without significant changes of where we are today, not large investments that we put in, not gross -- not spikes in production.

We’ve kind of talked about 200,000 barrels a day to 300,000 barrels a day of growth in the Permian kind of over the next number of years. It’s really trying to put a normalized view on 2026 based on how we’re operating today and the point of this was really to try to quantify the impact, not exactly, but there are some folks that believe that the renegotiation would have resulted in a significant reduction to the point where we couldn’t catch up and what we’re trying to say is really we’re going to be generally flat in 2026, which is really the first full year after the contract renegotiation and it’s always our jobs to work hard on improving that.

So as we get closer, we’ll be able to give better forecasts on it, but again, it’s really to quantify what we think the range is. We expect to be broadly flat with 2024 and 2026, and there could be upsides just as there could be downsides and more resolution will come as we see more.

Okay. Yeah.

Understood. Appreciate that, Willie.

Second question, maybe just going to NGL. Just curious how you guys are thinking about the hedging strategy out for 2025 and then more broadly or longer term, curious if there’s any opportunities over time to reduce that commodity exposure through contracts.

Yeah. So on the first part of the question is, we’re actively monitoring our hedging profile and we try to be opportunistic.

Liquidity decreases significantly after you get outside six months to nine months, so -- and it’s -- well -- and it’s very largely backward aided. So for us, we’re being opportunistic.

It doesn’t make sense to hedge at this point on a forward basis. We have some because it was higher, but it’s minimal, and so in our opinion, it’s be opportunistic.

As liquidity gets higher, market views get higher, and as the front end of the Crude markets roll up, and as gas prices moderate, you get to points where we’ll hedge again. But at this point, we’re not going to give any guidance on it, but that just gives you an assessment of right now the forward curve isn’t suggesting we should do it, and liquidity is not there to do anything besides.

And Spiro, as you know, we’ve got some additional capacity that’s coming on in Fort Saskatchewan and that is consistent with your question on how do we get and shift more towards a fee-based consistent cash flow stream. So that’s always our objective.

It’s just you got to be smart about how you go about it and pick the right times to contract.

Perfect. I’ll leave it there for today.

Thanks, gentlemen.

Thanks.

Thanks. Hi.

Good morning. When you look at the portfolio now after today’s announcement, are there assets at all that you would call out, aside from maybe BridgeTex, where contract rates are still meaningfully above market or are we at the point now where your contract rates are all pretty much more or less in line with where the market would be?

Keith, this is Jeremy. I would say that your assessment is correct, that BridgeTex is the one that’s outstanding.

We don’t operate the pipeline. That would be a better question for one.

But one thing I would say is BridgeTex demand is increasing and so one thing to pay attention to is Wink-to-Webster just extended to Beaumont, which has led to more demand for BridgeTex. You’ve got the downtime on Wink-to-Webster in June.

So longer term, we see that as a healthy pipeline with opportunity and we control the capacity between Midland and Colorado cities. We see benefits as those volumes increase as well.

And this is Al. The only thing I would add to what Jeremy said is, we assumed and made our assumption in this broadly flat 2026, the BridgeTex impacts as well.

Okay. That’s helpful.

And then just a small clarification, I think, it was Spiro’s question, just the 2026 Crude segment EBITDA being flattish. I just want to make sure that doesn’t include any bolt-on acquisition assumptions or use of free cash in that way, right?

It’s more just organic growth through the company.

Nothing major.

Got it. Okay.

Thank you.

Yeah. Hi.

Good morning, guys. Can you hear me all right?

Yeah. We can, Sunil.

Thanks. So on the Permian recontracting, so thanks for that update.

And I was kind of curious, since this was a major milestone and now that you have this behind you, how does that, if any, impact your kind of longer-term capital allocation strategy?

Yeah. The capital allocation strategy doesn’t change, right?

Our leverage is where we want it to be. We set a new range.

Our maximized free cash flow expects our CapEx to be in that $300,000 to $400,000 -- $300 million to $400 million range per year. We do look for opportunities that are high synergy, high return synergy opportunities for bolt-ons and we’ll continue to look for those opportunities because we think they’re creative and we can execute them on that.

And then the focus is, again, return of capital to unitholders. And I think, yeah, Tristan did ask the question.

If we perform better, we would certainly consider an increase above our target, as we have done in the last couple of years.

Understood. And then on Permian, seems like weather-related events kind of led to a sequential decline in your volumes.

I was kind of curious where things stand today. Have you seen enough recovery from those?

Obviously, you’re reiterating your full year expectations, but I was just kind of curious more near-term, what are you seeing in the Basin?

Sunil, this is Jeremy. There was an impact in January, February for about two weeks associated with the freeze.

Volumes have recovered. There’s been some issues with gas outages throughout the Basin that have caused some impact, but by and large, it’s in line with expectations.

There was a big growth in the fourth quarter of last year, which we expected flattish in the first part of this year and growth in the second half of the year and so we’re not changing our outlook at all based on this, this normal impacts of outages.

Okay. And just one clarification.

So, based on what we are seeing in gas prices and gas constraints, you are not expecting anything, any change to the second half-level growth. I understand there is a gas pipeline coming online.

So, that essentially, in your mind, helps resolve the constraint and kind of gets us the second half uptake in production. Is that fair?

That is very fair. That’s one way to look at it.

The other is, when gas prices are low, it doesn’t impact all shippers, right, some of that for transport and vast majority do ship those gas. Molecules of gas trying to get out of the Basin.

The other part of it is, when gas prices are like that, it moves capital allocation to oilier areas, lower GOR areas, which generally is beneficial for us. So, it’s not all bad.

Understood. Thank you.

Thank you, Sunil.

Perfect. Thanks for taking my question, guys.

Starting with the Saddlehorn transaction, can you guys provide any insight into the contract profile underpinning the pipe? Are those fairly long-dated or will there be some rolling in the next few years?

I think that’s a question for the Operator 1/0, but we’d say we’re very comfortable with acquisition price and long-term outlook for Saddlehorn.

Okay. Perfect.

And then, one kind of outside of your business realm, but we’re seeing more and more producers and midstream talk about 2026 being a very potentially constrained year on the gas side. Have any of your producers expressed any concerns or talked through the outer years with gas constraints maybe coming back in 2026?

I think, in general, all the conferences and calls we’ve seen so far is that there’s a general need for another pipeline to be sanctioned. And historically, new pipelines get sanctioned and we expect that to happen.

And anything would be transient, it would be quarters, it wouldn’t be years. And in our view, remember, we’re just talking about the last pipe.

We’re not talking about the whole base of production. So if you delay 100,000 barrels a day and grow to six months, that’s 100,000 barrels a day at that time, close to 6.5 million barrels a day.

It’s a very minor impact to the total Basin.

Gotcha. Perfect.

Well, I appreciate it, guys. Thanks.

Thanks, Zach.

Hi. Good morning.

Appreciate all the color and answers to the question thus far on the recontracting through 2025, but can you talk about perhaps how the five-year contract structure in 2028 leaves a massive amount of flexibility in the future prospects of the business, particularly around exports? Can you talk about the opportunity set that you’re looking at?

Yeah. This is Jeremy.

I’m not sure I completely understand the question, but what I would say is, it’s staggered. We gave you the average end of the duration.

The durations move over different years and we like to stagger contracts, and our intent is to continue to stay with long-term exporters and refiners in our contracting. So we’re managing that profile.

We’ll actively manage it. We see opportunity sets.

The long-haul price will be needed. The Permian oil in place is a big number and we’ll have production for a long time.

So this doesn’t concern us one bit. This was how we were able to get to the right balance of time, tenure and rate, and we’ll continue to manage that profile over time.

And Naomi, this is Willie. As we talk with our customers and our partners on this, this all fits their profile production, and if you think about it, you’ve got a limited amount of infrastructure that’s going to these markets now and we would like to think that the relationships are strong and that the customers will be sticky, because the offering that we have fits what they want to do, and so it’s not a matter of people wanting to shift to completely different markets.

I would think that as we are good partners that we’ll continue to have those and it’s really a renegotiation of term and tenure and tariff at that time.

That is helpful. Maybe as a follow-up, how should we think about Permian production cadence for the remaining of the year?

Should we expect further gathering bolt-on transactions to drive production given the increased activity?

I think we’ve shared that our expectations for the Permian really are 200,000 barrels a day to 300,000 barrels a day of growth from the end of the year to the end of the year of 2023 to 202024, and it’s really back half, Q3 and Q4, that we’ll see the increase.

Great. Thanks for all the color.

Have a great rest of your day.

Thanks, Naomi.

Good morning, guys. Thanks for the time.

My first question on your Canadian assets, specifically, you’ve had some nice market-based results in past quarters on the Canadian Crude spreads and NGL markets. I’m just wondering, how are those continuing to trend?

Are they still up and to the right as they’ve been?

Our view is the same as our outlook for the year. We tended to bring those down on the market-based opportunities as TMX starts up, so our views impact it.

It’s included in our guidance. And what I would say is, we view that as positive long-term for our Canadian assets.

It’s more production growth and you’re probably in a constrained environment, again, in two years to three years, so we think more volume will be good for those assets on both the NGL and the Crude side. While there may be fewer market-based opportunities, it could lead to higher tariff-based opportunities.

That’s great to hear. And just a quick one, just what you just were mentioning on the Permian...

…to add is…

Oh! Go ahead.

Sorry.

That movement to the West Coast is going to reorganize how things move in the U.S. to make up for that, so those barrels are not coming into the U.S., so that could create other opportunities for some of our other pipes in the Mid-Continent.

Great add. And then I was just asking on, you just mentioned on Permian growth.

Is the majority of that still going to come from the Del? I think last quarter you talked about maybe 170 Del rigs versus 120 Midland, so do you anticipate that to be the case for the remainder of the year?

Yes. The activity balance hasn’t really changed very much, but we do see some growth in the Midland Basin, but we think it’ll be disproportionately in the Del rigs.

Helpful. Thank you all.

Hi. Good morning.

Good morning, Jeremy.

Just wanted to come back to the recontracting, if I could, I wanted to better understand, I guess, when you say terms consistent with rates, what that means exactly? Does that mean like there’s a higher amount contracted at a lower rate or is there something else?

Just wondering why it’s consistent with rates and not just those are the rates?

Well, it’s a mix of what we’ve got, and it’s -- well, we don’t really want to get into the specifics of every pipe and what the tariff is. I think the key point on that, Jeremy, is when you look at the recently built pipes, it’s $1.25 to $1.50, and essentially what we’re telling you is that we’ve been able to recontract successfully with our partners at rates that are competitive with that.

And going forward, I think it’s a reset in that we don’t have, we have less that are far out of market as we go forward and as the Basin tightens, we would expect that there could be some pressure upwards on that.

Got it. That’s very helpful.

Thank you. And then just wanted to come back to the guidance, if I could.

Appreciate that early in the year and you don’t want to move it just yet, but with the acquisitions, presumably bringing upside to results for the year, are there other, I guess, headwinds that have materialized so far that would be an offset or just trying to better understand the gives and takes or just as the year progresses, you would account for that upside later?

Jeremy, this is Al. The acquisition of the $110 million is the impact that will be seen this year would be very modest and well within the range we have.

Our base business is performing in line with expectation, as Willie mentioned on his prepared remarks. So, if you run the math on $110 million and recognize that it’s only a partial year, it was not enough for us to allow for in our business.

But our business is performing in line with what we expected.

Hey, Jeremy. This is Willie again.

Just a clarification. The specific $1.25 to $1.50, that was really around Cactus I.

However, we’ve got other pipelines that are in the mix and we have a weighted average concept that we look at. But it really, the $1.25 to $1.50 was really just the Cactus I recontracting.

Got it. Very helpful.

Thank you.

Thank you.

Hey, guys. Good morning.

Thanks for the time. I just figured now that you’re having some of these conversations with your shippers around kind of back half of the decade volumes and rates, we’d just be curious if there’s anything you can share on how the market’s developing for kind of Houston versus Corpus dynamics, whether or not some of the big export projects proposed out there are kind of playing into those conversations yet.

Appreciate it.

Yeah. I would say they had absolutely no impact on the discussion that we had.

I think the view of does an offshore export facility get built, you have to think about there’s already a couple million barrels a day headed to Houston and close to three headed to Corpus, right? So those balances may not change very much and you have production growth in between.

We’re talking about a project three years to four years from now where you could have 0.5 million barrels a day to 800,000 barrels a day more production. I think you’re going to move inland, less efficient docks offshore, maybe take some production growth, but you’ll still be full to Corpus.

So I don’t think -- it didn’t impact the discussions at all and it’s more of an and as opposed to or.

All right. That’s fair.

Maybe just one last one. Maybe just another comment on the weather challenges or otherwise in first quarter.

Understand kind of general Permian trajectories intact. Just when we’re looking at kind of Permian gathering versus long-haul, was there more of an impact on one versus the other?

And maybe just how we think about a 2Q trajectory versus a second half pickup? Thanks.

Yeah. This is Jeremy.

The way I look at this is the gathering was more impacted by whether the markets impacted the long-haul. It is just the matter of the bid.

Was it better for our shippers to buy at Midland, buy at the end of the pipe or at the dock? And so sometimes they’ll just change their behaviors and how they ship, and it could be a measure of what are inventories in Cushing and what are demands and turnarounds in Cushing.

So I’d say the long-haul is impacted by market. The gathering was more impacted by the weather.

All right. Got it.

Thank you.

Hi, Theresa.

Good morning. Thank you for taking my questions.

First, I wanted to ask about the upcoming maintenance on Wink-to-Webster and how that might translate to incremental throughput on Basin pipeline and maybe your Cushing assets given the slot capacity there. Is that an opportunity for incremental earnings, either from a throughput involving metric perspective or marketing optimization?

So, Theresa, this is Jeremy. The way I look at it is the 10 days of scheduled downtime, there’s ways to get it out, right?

A lot of that will -- the export pipes to the Gulf Coast will be full. There’s some capacity there.

The barrels do need to get to Colorado City, which we can assist with. The barrels will likely flow onto BridgeTex as a result of Wink-to-Webster being down.

So you see more BridgeTex flows, more Colorado City flows, and when it gets to Colorado City, you’re likely to see more Basin flows. So I think all three of those could happen.

Plus, you’ll see significant flows through all the Corpus pipes.

Understood. And on the WCS front, as TMX is line filling, we’re seeing the differentials come in at this point.

Can you give some color on how that’s impacting your marketing activities and maybe just broadly, looking past this, if you have a rule of thumb on the magnitude of impact that, differentials on WCS specifically impacts the Crude segment just from a quarter-to-quarter basis, that’d be helpful?

Thanks, Theresa. I don’t think we’ll give specific guidance, but what I would say is it will be included in our outlook.

I’d say there’s plenty of ways for us to optimize around our assets between grades other than WCS. WCS is one component of the marketing activities in Canada, but there also will be storage opportunities and other things as it starts up, no pipes.

Pipes as complicated as that will have difficulty starting up, and it’ll create opportunities. Also, flow changes of that magnitude away from the U.S., so it may end up more tariff-based opportunities, less market-based opportunities, but we would expect the market-based opportunities to come back as Canadian production grows.

Theresa, this is Willie. I think the key point on this is we’ve always said with the shift in flow, it’s 400,000 barrels a day to 600,000 barrels a day potentially.

Short-term, there could be some blips. Long-term, we think it’s very healthy, because it sends good price signals to the Canadians to develop more resource and it’s, quite frankly, a great opportunity for the Canadian resource base to increase.

And this is Al. The only thing I would add is that, it’s actually coming online and this stuff is happening pretty well in line with what we assumed in our original February guidance.

Got it. Thank you.

Thank you. As always, we enjoy visiting with you.

Thanks for dialing in and your ongoing attention and support of what we’re doing. We look forward to seeing you out on the road.

Talk to you soon.