Plains All American Pipeline LP Q1 FY2024 Earnings Call

Thank you, Latif. Good morning, and welcome to Plains All American's 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 that we laid out in February. For the first quarter of ‘24 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 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 has been finalized on terms that are consistent with the rates in the range of $1.25 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 to 500 basis points above our weighted average cost of capital.

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.

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 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 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 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 Michael Blum of Wells Fargo.

I wanted to start by asking about the guidance. You had a strong Q1 and completed the bolt-on acquisition, so could you explain why the 2024 guidance hasn't been increased? Also, do you believe you are on track to exceed the $0.15 per year distribution growth, given that the business seems to be performing well?

Yes, 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 in 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. 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 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 associated with 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, as you know, there are many factors involved, and it wouldn't be accurate to provide guidance looking ahead to 2026. The tight balance between supply and demand regarding capacity, operating costs, and production all play a role. While I won’t detail everything, we are considering our business in 2026 without significant changes from our current state, such as large investments or spikes in production. We have previously discussed growth in the Permian of about 200,000 to 300,000 barrels a day over the next few years. Our aim is to present a normalized view for 2026 based on our current operations. The intention here is to quantify the impact—though not precisely. Some believe that renegotiating contracts would lead to a sizable reduction that allows us to catch up, but we are indicating that we expect to remain generally flat in 2026, which will be the first full year following the contract renegotiation. It is our responsibility to strive for improvement. As we approach that timeframe, we'll provide a better forecast. For now, we anticipate being broadly flat compared to 2024 and 2026, with potential for both upside and downside. More clarity will emerge as we gather additional information.

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's any opportunities over time to reduce that commodity exposure through contracts.

We are actively monitoring our hedging profile and aim to take advantage of opportunities as they arise. Liquidity drops significantly beyond six to nine months, and the market is primarily backwardated. Therefore, we are cautious about hedging on a forward basis right now. While we have some hedges due to previous higher prices, they are minimal. We believe there will be better opportunities to hedge as liquidity and market sentiment improve, particularly as the front end of the crude markets strengthens and gas prices stabilize. Currently, we won't provide guidance on this topic, but it reflects our assessment of the situation. The forward curve does not indicate a need to hedge, and liquidity is not sufficient for any significant activity.

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. 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.

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's outstanding. We don't operate the pipeline. It would be a better question for one. 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, and 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. Our maximize free cash flow, 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 on that. And then the focus is, again, 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 two weeks due to the freeze. Volumes have recovered. There have been some issues with gas outages throughout the basin that have caused some impact. Overall, it's in line with expectations. We saw significant growth in the fourth quarter of last year, which we anticipated would flatten in the early part of this year and increase in the second half. Therefore, we are not adjusting our outlook based on the typical impact of averages.

Okay. I just wanted to clarify. Given the current situation with gas prices and constraints, are you still maintaining your expectations for levered growth in the second half? I understand there is a gas pipeline coming online, which should help alleviate the constraints and support a production increase 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 for 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 like that, 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 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 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 talk through the outer years with gas constraints maybe coming back?

I believe that generally, the conference calls so far indicate a clear need for an additional pipeline, as previously mentioned. Traditionally, new pipelines get approved, and we anticipate this will occur. Any delays would be temporary, lasting only a few quarters rather than years. It's important to remember that we're discussing the latest pipeline and not the entire production base. Therefore, if there is a six-month delay impacting 100,000 barrels a day of growth, that's a small fraction compared to nearly 6.5 million barrels a day at that time. The overall effect on the total basin would be minimal.

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

Appreciate all the color and answers to the question as 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 entirely grasp the question. However, I would say that it's staggered. We provided the average duration at the end. The durations vary across different years, and we prefer to stagger contracts. Our goal is to maintain relationships with long-term exporters and refiners in our contracting approach. We're actively managing that profile. We see potential needs for long-term supply. The amount of oil in the Permian is significant, and we'll have production available for a long time. This does not concern us at all. This is how we achieved the right balance of time, tenure, and rate, and we will keep managing that profile as we move forward.

And Naomi, this is Willie. As we engage with our customers and partners, everything aligns with their production needs. There's a limited amount of infrastructure serving these markets right now. We believe that our relationships are strong and that customers will remain loyal because our offerings meet their requirements. It's not about customers wanting to move to entirely different markets. I think that as we maintain strong partnerships, we will continue to develop those relationships, and it will really be a renegotiation of terms, duration, and pricing at that point.

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 to 300,000 barrels a day of growth from the end of the year to the end of 2023 to 2024, and it's really back half Q3 and Q4 that we'll see the increase.

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

My first question is 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 perspective aligns with our outlook for the year. We attempted to reduce those figures based on market opportunities as TMX commences operations. Our expectations are reflected in our guidance. I would mention that we see this as a positive long-term outlook for our Canadian assets, which will likely see increased production growth, placing us again in a constrained environment in two to three years. Consequently, we believe that more volume will benefit those assets on both the NGL and crude fronts. Although there may be fewer market opportunities, this could result in increased tariff-based opportunities. That's encouraging to know. Regarding your question about Permian growth, is the majority still expected to originate from Delaware? Last quarter, you mentioned around 170 Delaware rigs compared to 120 in Midland. Is this still the anticipated situation 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 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?

It's a combination of factors we have in play. We prefer not to dive into the specifics of each pipeline and its tariff. The main point, Jeremy, is that for the newly constructed pipelines, the rates are between $1.25 and $1.50. What we're indicating is that we've successfully negotiated recontracting with our partners at rates that are competitive with those figures. Looking ahead, we anticipate a shift in that we will have less exposure to market fluctuations. As demand in the basin increases, we could see some upward pressure on those rates.

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, 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 we'll be seeing this year would be very modest and 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. But our business is performing in line with what we expected.

Jeremy, this is Willie. 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 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, 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 appreciate it.

I would say they had no impact on our discussions. The perspective on the offshore export facility is developing. It's important to note that there are already a couple of million barrels a day secured in Houston, along with close to 3 million barrels. Therefore, those balances are unlikely to change significantly, especially with production growth in between. We're looking at a project that is projected to be 3 to 4 years away, which could result in an additional 0.5 million to 800,000 barrels a day in production. While there may be some production growth from less efficient docks offshore, Corpus will still be full. So, in summary, it did not affect our discussions at all; it’s more about adding to the conversation rather than taking away from it.

All right. That's fair. Maybe just one last one. Maybe just another comment on the weather challenges or otherwise in the 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.

This is Jeremy. The way I'd look at this is the gathering was more impacted by weather. The markets impacted the long haul. It's just a matter of where the bid is better for our shippers to buy at Midland, at the end of the pipe, or it's the dock. Sometimes they'll just change their behaviors and how they ship, and it could be a measure of what are inventories in Cushing and water demand and turnarounds in Cushing. So I'd say long-haul impacted by market. The gathering was more impacted by the 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 see the scheduled downtime of 10 days as manageable; there are ways to address it. A lot of the export pipes to the Gulf Coast will be filled, but there is some capacity available. The barrels need to reach Colorado City, and we can help with that. The barrels will likely continue onto BridgeTex due to the lines being down. Therefore, we can expect increased flows through BridgeTex and Colorado City. Once it arrives in Colorado City, we are likely to see more flows from the basin. I believe all three of these scenarios could occur, along with 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 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 rates over and WCS. WCS is one component of the marketing activities in Canada. There will also be storage opportunities and other things as it starts up. Pipe is complicated; there will be the difficulty starting up, and it will 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 expect the market-based opportunities to come back as 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 think 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 actually coming online, and this stuff is happening pretty well in line with what we assumed in our original February guidance.

Thank you. As always, we enjoy visiting with you. Thanks for dialing in and for your ongoing attention and support of 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.