Plains Gp Holdings LP Q1 FY2024 Earnings Call

Thank you for your patience, and welcome to the First Quarter 2024 Earnings Conference Call for PAA and PAGP. I will now turn the call over to Blake Fernandez, Vice President of Investor Relations. Please proceed.

Thank you, Latif. 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. A 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. Consistent with those themes, earlier this morning, we reported first-quarter results that are in line with our expectations, which reflects progress towards our full year 2024 targets and provides us with confidence in our ability to deliver on the plan we laid out in February. For the first quarter of '24, 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 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 5 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 1 capacity that have been finalized on terms that are consistent with the rates in the range of $1.25 to $1.50 per barrel, which will become effective in September 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 broadly flat adjusted EBITDA in 2026 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 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 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 to PAA of $718 million. Slides 10 and 11 in today's appendix contain walks 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 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 provide 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 unitholders, 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 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 shared 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 bottom line 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 into 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. Latif, we're ready to open the call for questions, please.

Thank you. Our first question comes from the line of Michael Blum of Wells Fargo.

My first question is regarding the guidance. You had a strong Q1 and completed a bolt-on acquisition. Could you explain why you haven't increased the 2024 guidance? Also, do you believe you’re on track to exceed the $0.15 per year distribution growth, considering the business seems to be performing well?

Yes, Michael, thanks for the question. This is Willie. It is early in the year, and 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. However, we do remain confident in our performance this year. I would characterize it as cautiously optimistic that we'll be able to perform well within the range.

Okay. Understood. And then I wonder if you can comment on the rates for the contract extensions for Cactus II and the Sunrise Basin. Were those largely consistent with prior rates, and just extended the duration? Or did you also see changes in the rates there?

Michael, 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 as it got towards tariff. So effectively, folks are paying tariffs to get there, and that's the right balance for us for a long-term rate. On Cactus II, the extensions were associated with contract extensions related to their options to extend. So they basically elected their options to extend the existing contracts.

Our next question comes from the line of Tristan Richardson of Scotiabank. Is your line muted? Shall I move on? Yes. Thank you. Okay. One moment. Our next question comes from the line of Spiro Dounis of Citi.

So maybe I just want to go back to the 2026 comment. Willie, I totally appreciate you're not giving guidance today. But I 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're thinking 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 you as well.

Yes, Spiro, there are numerous factors to consider here. It wouldn't be accurate to provide guidance by looking all the way to 2026. As you know, the balance of supply and demand, operational costs, and production all play significant roles. While I won’t go into detail, we’re trying to envision our business in 2026 without major changes from our current situation, without large investments, and without significant spikes in production. We anticipate growth in the Permian of around 200,000 to 300,000 barrels per day over the next few years. The aim is to present a normalized outlook for 2026 based on our current operations. We are attempting to quantify the impact, though not precisely. There are some who believe that the renegotiation could lead to a significant decrease that would allow us to catch up. We expect to remain generally flat in 2026, which will be the first full year following the contract renegotiation. It's always our responsibility to focus on improvement. As we approach that time, we will be able to offer more accurate forecasts, but for now, we’re trying to define what the range looks like. We anticipate remaining mostly flat when comparing 2024 to 2026, with potential upsides and downsides, and more clarity will emerge as we receive further details.

Okay. Yes. 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 are any opportunities over time to reduce that commodity exposure through contracts.

So on the first part of the question, we're actively monitoring our hedging profile, and we try to be opportunistic. Liquidity decreases significantly after you get outside 6 to 9 months, and it's while generally very backward dated. 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. In our opinion, it's based on being opportunistic as liquidity increases and market views get higher. The front end of the crude markets rolls up, and as gas prices moderate, we will hedge again. At this point, we’re not going to provide any guidance on it, but I hope that gives you an assessment of where we are right now. The forward curve isn't suggesting we should do it, and liquidity is not there to do anything exciting.

And Spiro, as you know, we've got some additional capacity 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. That's always our objective. It's just you need to be smart about how you go about it and pick the right times to contract.

Our next question comes from the line of Keith Stanley of Wolfe Research.

When you look at the portfolio now after today's announcement, are there assets that 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 is outstanding. We don't operate the pipeline, so it would be a better question for them. But one thing I would say is BridgeTex demand is increasing. One thing to pay attention to is Wink-to-Webster or 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 City, so we see benefits as those volumes increase as well.

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.

Our next question comes from the line of Sunil Sibal of Seaport Global.

Can you get me all right?

Yes, we can, Sunil.

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?

Yes, the capital allocation strategy doesn't change, right? Our leverage is where we want it to be. We set a new range. We maximize free cash flow and expect our CapEx to be in that $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 accretive and we can execute them effectively. The focus is, again, on the return of capital to unitholders. And I think, yes, 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, it 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 clear more near term what are you seeing in the basin?

Sunil, this is Jeremy. There was an impact in January and February for about 2 weeks associated with the freeze. Volumes have recovered. There have been some issues with gas outages throughout the basin that have caused some impact. However, by and large, it's in line with expectations. There was a big growth impact 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. So we're not changing our outlook at all based on the normal impact of averages.

Okay. Just to clarify, given the current gas prices and constraints, do you anticipate any changes to the levered growth for the second half? I understand there is a gas pipeline that will be coming online, which should alleviate the constraints and contribute to increased production in the second half. Is that correct?

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 them have fixed transport, and the vast majority do. It's just those last molecules of gas trying to get out of the basin. The other part of it is when gas prices are low, most capital allocation goes to oilier areas, lower GOR areas, which generally is beneficial for us. So it's not all that.

Our next question comes from the line of Zack Van Everen of TPH & Company.

Starting with the Saddlehorn transaction, can you 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 to hold on, but we'd say we're very comfortable with the acquisition price and long-term outlook for the coming years.

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

I think in general, all the conference calls you've seen so far indicate that there's a general need for another pipeline, as mentioned. Historically, new pipelines get sanctioned, and we expect that to happen. Anything would be transient, it would be quarters, not years. In our view, keep in mind, 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 of growth by 6 months, that's 100,000 barrels a day out of, at that time, close to 6.5 million barrels a day. It's a very minor impact to the total basin.

Our next question comes from the line of Naomi Marfatia of UBS.

Appreciate all the color and answers to the question so far on the recontracting through 2025. But can you talk about perhaps how the 5-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?

This is Jeremy. I'm not sure I completely understand the question. But what I would say is it's staggered. We provided the average end of the duration. The durations move over different years, and we like to stagger contracts — our intent is to continue to stay with long-term exporters and refiners in our contracting. So we're managing that profile actively. We see opportunities that the long-haul highs 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 is 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.

Naomi, this is Willie. As we talk with our customers and our partners about this, it all fits their production profiles. With limited amount of infrastructure going to these markets now, we believe that the relationships will remain strong and that the customers will be sticky because our offering fits what they want. It's not a matter of customers wanting to shift to completely different markets. I think that as we continue to be good partners, we will maintain those relationships, and this is really a renegotiation of term, tenure, and tariff at that time.

That is helpful. Maybe as a follow-up, how should we think about the 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 to 300,000 barrels a day of growth from the end of the year to the end of 2023 through 2024, and it's really in the back half, Q3 and Q4, that we'll see the increase. Great.

Our next question comes from the line of Neal Dingmann of Truist Securities.

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?

So our view is the same as our outlook for the year. We tried to bring those down on the market-based opportunities as TMX starts up. Our guidance includes the impacts. We view that as positive long-term for our Canadian assets as we will see more production growth, and you're probably in a constrained environment again in 2 to 3 years. So we think more volume will be good for those assets on both the NGL and the crude side. Though there may be fewer market-based opportunities, it could lead to higher tariff-based opportunities.

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 Delaware? I think last quarter, you talked about maybe 170 Delaware rigs versus 120 Midland. So do you still anticipate that being 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. However, we think it will be disproportionately in the Delaware Basin.

Our next question comes from the line of Jeremy Tonet of JPMorgan Securities. Go ahead, Jeremy.

Just want 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. We don't really want to get into the specifics of every pipe and what the tariff is. I think the key one on that, Jeremy, is when you look at the recently built pipes, it's $1.25 to $1.50. Essentially, what we're telling you is we've been able to recontract successfully with our partners at rates that are competitive with that. Going forward, I think it's a reset in that we have less far out of market rates as we move forward, and as the basin tightens, we would expect that there could be some upward pressure on that.

Got it. That's very helpful. 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 headwinds that have materialized so far that would be an offset? Or just as the year progresses, you would account for that upside later?

Jeremy, this is Al. The acquisition of the $110 million will have a very modest impact this year and will be well within the range we have. Our base business is performing in line with expectations, as Willie mentioned in his prepared remarks. 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. However, our business is performing as expected.

Jeremy, this is Willie. Just for clarification, the specific $1.25 to $1.50 was really around Cactus I. However, we've got other pipelines in the mix, and we look at a weighted average concept. The $1.25 to $1.50 is really just the Cactus 1 recontracting.

Our next question comes from the line of John Mackay of Goldman Sachs.

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, I would just be curious if there's anything you can share on how the market is 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?

I would say they had absolutely no impact on the discussions we've had. The view of the offshore export facility is being built. You have to think about there's already a couple of million barrels a day inked in Houston and close to 3 headiness, right? So those balances may not change very much, and you have production growth in between. We're talking about a project 3 to 4 years from now, where you could have 0.5 million to 800,000 barrels a day more production. I think you're going to move in and have less efficient docks offshore, which may take some production growth, but you'll still be full to Corpus. So I don't think it impacted our discussions at all, and it's more of an and as opposed to or.

That's fair. Maybe just one last one. Maybe just another comment on the weather challenges or otherwise in the first quarter, understand the general Permian trajectories intact. Just when we're looking at 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.

This is Jeremy. The way I'd look at this is that gathering was more impacted by weather. The market impacts the long haul. It's a matter of where the bid is; it's better for our shippers to buy at Midland, buy at the end of the pipe, or at the dock. Sometimes they'll just change their behaviors and how they ship, and it could be a measure of what the inventories are in Cushing and water demand and turnarounds in Cushing. So I'd say long haul is impacted by market factors, while gathering was more impacted by weather.

Our next question comes from the line of Theresa Chen of Barclays. Theresa?

First, I'd like to ask about the upcoming maintenance on Wink-to-Webster. And how that might translate to incremental throughput on basin pipeline and maybe you are pushing assets given the spot capacity there. Is that an opportunity for incremental earnings, either from a throughput metric perspective or marketing optimization?

So Theresa, this is Jeremy. I look at it as the 10 days of scheduled downtime. There are ways to get it out, right? A lot of that will involve the export pipes to the Gulf Coast being full. Some capacity there exists. The barrels do need to get to Colorado City, which we can assist with. Given the lines are down, you will likely see more BridgeTex flows and more Colorado City flows. When it reaches Colorado City, we're likely to see more basin flows as well. So I think all three could happen, plus you'll see significant flows through all the Corpus pipes.

Understood. And on the WCS front, as TMX is infilling, 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 would be helpful. Thanks.

I don't think we'll provide specific guidance, but what I would say is it will be included in our outlook. There are plenty of ways for us to optimize around our assets between rates and WCS. WCS is one component of the marketing activities in Canada. However, there also will be storage opportunities and other things as it starts up. Pipe is complicated and will have difficulty starting up, which will create opportunities. The flow changes of that magnitude will affect the U.S. So it may end up more tariff-based opportunities and fewer market-based opportunities. However, we expect market-based opportunities to come back as we see Canadian production growth.

Theresa, this is Willie. I think the key point on this is we've always said with the shift in flow, 400,000 to 600,000 barrels a day potentially short-term, there could be some blips. Long-term, we believe it's very healthy because it sends good price signals to the Canadians to develop more resources and it's quite frankly, a great opportunity for the Canadian resource base to increase.

This is Al. The only thing I would add is that it's coming online, and this is happening pretty well in line with our original February guidance.

I would now like to turn the conference back to Willie Chiang for closing remarks. Sir?

Thank you. As always, we enjoy visiting with you. Thanks for dialing in and your ongoing attention and support in what we're doing. We look forward to seeing you out on the road. Talk to you soon.

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