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- Globe and Mail
Plains GP (PAGP) Q2 2025 Earnings Call Transcript
Date Aug. 8, 2025 2:00 p.m. ET Call participants Chairman and Chief Executive Officer — Willie Chiang Executive Vice President and Chief Financial Officer — Al Swanson Executive Vice President and Chief Operating Officer — Chris Chandler Executive Vice President and Chief Commercial Officer — Jeremy Goebel Vice President, Investor Relations — Blake Fernandez Need a quote from a Motley Fool analyst? Email pr@ Takeaways Adjusted EBITDA -- Plains reported $672 million of adjusted EBITDA for Q2 2025, including contributions from both the crude oil and NGL segments. Crude oil segment adjusted EBITDA -- Crude oil segment adjusted EBITDA was $580 million, benefiting sequentially from Permian volume growth, bolt-on acquisitions, and higher throughput as refiner customers returned from downtime. NGL segment adjusted EBITDA -- Adjusted EBITDA for the NGL segment was $87 million, with a sequential decrease attributable to seasonality and lower frac spreads. NGL business divestiture -- Agreements to sell substantially all of the NGL business to Keyera for approximately $3.75 billion, as announced in June 2025, with closure expected in 2026, will transition Plains' focus toward crude oil midstream. Net proceeds from NGL sale -- Approximately $3 billion in net proceeds from the NGL business sale are anticipated, targeted for disciplined bolt-on M&A, preferred unit repurchases, and opportunistic common unit buybacks. Bolt-on acquisition activity -- Plains completed five bolt-on deals year to date in 2025, totaling approximately $800 million, including the acquisition of a further 20% interest in BridgeTex Pipeline Company LLC for $100 million net to Plains, raising its overall interest to 40%. Full-year 2025 adjusted EBITDA guidance -- Maintained at $2.8 billion to $2.95 billion for full-year 2025; management indicated both EBITDA and Permian growth outlooks for the year are likely tracking toward the lower half of their respective ranges. Permian volume growth outlook -- The stated range remains 200,000 to 300,000 barrels per day for full-year 2025 guidance, but current conditions suggest results in the lower half. 2025 adjusted free cash flow guidance -- $870 million of adjusted free cash flow is expected for 2025, excluding changes in assets and liabilities, reflecting the impacts of 2025 growth capex and bolt-on transactions. Growth capital guidance increase -- Full-year 2025 growth capex revised up by $75 million to $475 million, primarily to fund new Permian and South Texas lease connects, terminal expansions, weather delays, and scope changes. Maintenance capital guidance -- Trending near $230 million for fiscal 2025. This is $10 million below the initial forecast. BridgeTex pipeline positioning -- Plains and ONEOK will jointly work to optimize pipeline capacity and fill by leveraging their respective gathering system connections; all interests acquired are outside the ORIX JV. Retained U.S. NGL assets -- Retained U.S. NGL assets are expected to contribute $10 million to $15 million of EBITDA in 2025, with an indicated value of around $200 million (valuation estimate provided by management); management expressed intent to divest these over time rather than pursue a larger NGL strategy. Contract roll-offs -- Second-half 2025 will see lower contracted rates for Cactus II, Cactus I, and Sunrise, offset in part by Permian production growth and recontracting, as previously guided. Distribution growth messaging -- Management clarified there is no change in intent regarding 'multiyear sustainable' distribution growth despite altered slide language; future growth depends on successful redeployment of divestiture proceeds. Summary Plains GP Holdings (NASDAQ:PAGP) announced the divestiture of its NGL business to Keyera for approximately $3.75 billion in June 2025, marking a significant strategic exit from the Canadian NGL market and a sharper focus on crude oil infrastructure. Capital deployment priorities encompass bolt-on M&A, capital structure optimization, and potential unit buybacks, enabled by expected net proceeds of approximately $3 billion from the NGL transaction, as disclosed in June 2025. Despite confirming full-year EBITDA and Permian volume guidance ranges, management signaled that both metrics—full-year 2025 EBITDA guidance and Permian growth outlook—will likely land in the lower half of their respective ranges, due to factors including contract repricing and market volatility. Crude oil segment adjusted EBITDA performance was aided by Permian growth and contributions from recent bolt-on acquisitions, while NGL results reflected seasonal and spread-driven declines and are now classified largely as discontinued operations. Growth capital guidance for 2025 was raised by $75 million to $475 million to accommodate new lease connections and terminal expansions, with management noting that part of the increase in 2025 capital expenditures reflects deferred spending from last year. Retained U.S. NGL operations remain limited in scale, with eventual divestiture expected and no indication of a growth strategy for these residual assets. Distribution growth remains a core goal, but interim capital deployment will be guided by opportunities to redeploy divestiture proceeds 'in a way that's accretive to DCF.' Demand commentary from management emphasized ongoing refining strength and an absence of the previously anticipated slowdown in crude and product demand over the last six months. Industry glossary Bolt-on acquisition: Purchase of smaller, strategically complementary assets intended to expand or enhance an existing business platform. Frac spread: The difference between the price of natural gas liquids extracted and the cost of the natural gas feedstock used to generate them, often impacting profitability for NGL segment operators. ORIX JV: Refers to a joint venture co-owned by Plains and ORIX; in this context, BridgeTex interest acquisitions are outside the scope of this JV. DCF (Distributable Cash Flow): Cash available to be paid to unit holders after capital expenditures and other obligations, commonly used in pipeline MLP context. Full Conference Call Transcript Willie Chiang: Thank you, Blake. Good morning, everyone, and thank you for joining us today. Earlier this morning, we reported solid second quarter adjusted EBITDA attributable to Plains of $672 million, which I will cover in more detail. In June, we announced the execution of definitive agreements to sell substantially all of our NGL business to Keyera for approximately $3.75 billion, with an expected close in 2026. Initial investor feedback has been positive, and we view this as a win-win transaction for both parties. Plains will exit the Canadian NGL market at an attractive valuation while Keyera will receive highly complementary critical infrastructure in a strategic market. From a Plains perspective and as highlighted on slide four, this transaction will result in a streamlined crude oil midstream entity. With less commodity exposure, a more durable and steady cash flow stream, and substantial financial flexibility to further execute on our capital allocation framework. With approximately $3 billion of net proceeds from the sale, we expect to continue focusing on disciplined bolt-on M&A to extend and expand our crude oil-focused portfolio as well as opportunities to optimize our capital structure, including potential repurchases of Series A and B preferred units, along with opportunistic common unit repurchases. Building upon the foundation of our disciplined capital allocation framework, we announced a bolt-on acquisition of an additional 20% interest in BridgeTex Pipeline Company LLC for an aggregate cash consideration of $100 million net to Plains. This brings our overall interest in the joint venture to 40%. Both Plains and ONEOK have extensive upstream gathering systems, and both companies are committed to optimizing the operating capacity on the pipeline. In addition, this transaction is expected to provide risk-adjusted returns in line with Plains' bolt-on framework. Year to date, we've completed five bolt-on transactions totaling approximately $800 million, and we've consistently maintained the view that there is a runway of opportunities for Plains to advance its bolt-on strategy. As illustrated on slide five and as proven over the last few years, we continue to execute on that backlog of opportunities. Additionally, the financial flexibility that'll be created by our recent NGL announcement further enhances our commitment and capacity to pursue these and other opportunities, provided they offer attractive returns. With that, I'll turn the call over to Al. Al Swanson: Thank you, Willie. Prior to discussing further details of our second quarter results, I would like to reiterate that following our NGL announcement, the majority of the NGL segment has been reclassified as a discontinued operation. To ensure consistent financial disclosure to the market, we have also included pertinent information reconciling these changes with our original 2025 guidance for the NGL segment. Turning to the second quarter, we reported crude oil segment adjusted EBITDA of $580 million, which benefited sequentially from Permian volume growth, contributions from recent bolt-on acquisitions, and higher throughput associated with our refiner customers returning from downtime in 2025. Moving to the NGL segment, we reported adjusted EBITDA of $87 million, which stepped down sequentially due to normal seasonality and lower quarter-on-quarter frac spreads. Slides six and seven in today's presentation contain adjusted EBITDA walks that provide additional details on our performance. Regarding guidance, our full-year 2025 EBITDA range of $2.8 to $2.95 billion remains intact. Consistent with our communication last quarter, in the prevailing environment, both our EBITDA guidance and the Permian growth outlook of 200,000 to 300,000 barrels per day would likely be in the lower half of their respective ranges. A summary of our 2025 guidance metrics is located on slide eight. As for capital allocation, which is illustrated on slide nine, for 2025, we expect to generate approximately $870 million of adjusted free cash flow, excluding changes in assets and liabilities. Our adjusted free cash flow guidance reflects the impact of bolt-on acquisitions, including the acquisition of the interest in BridgeTex Pipeline, as well as our revised 2025 growth capital guidance, which has increased $75 million to $475 million. The capital investment increase is primarily associated with new projects, including Permian and South Texas lease connects, and Permian terminal expansions, in addition to weather delays and scope changes on other projects. While 2025 growth capital was above our initial guidance, maintenance capital is trending closer to $230 million, which is $10 million below our initial forecast. With that, I'll turn the call back to Willie. Willie Chiang: Thanks, Al. As illustrated on Slide 10, we've made significant progress on our strategy over the last several years. This begins with a portfolio of world-class assets, value has been unlocked through the capabilities of our Plains team along with collaboration with our customers. Our strategy is grounded in our established financial priorities, with a focus on generating substantial free cash flow, maintaining financial flexibility, and increasing return of capital to our unitholders through disciplined execution in each of these areas. The divestiture of our NGL business marks a significant step in the strategic direction of Plains. By reallocating resources and capital towards our legacy crude oil operations, where we have significant size and scale, we will be better positioned to enhance our focused portfolio. This move not only increases our financial flexibility, but it also underscores our resolve to streamline operations and drive growth while generating strong returns for our unitholders. Our strategy centers on the view that crude oil will remain essential to global energy and society for decades. Despite near-term volatility, we're confident in our ability to navigate current market dynamics. And we expect fundamentals to improve longer term due to continued population and economic growth driving demand. We anticipate that new OPEC plus supply will be absorbed, reducing spare capacity, and limited long lead project and resource additions will increase the reliance on North American onshore production. Plains will continue to be a vital infrastructure provider to meeting the growing need for reliable energy across global markets. In closing, our efficient growth strategy, financial flexibility, and commitment to execution have positioned us well to capitalize on opportunities and manage challenges with resilience. I'm confident in our position. At this point, we'll look forward to your questions. Blake, would you lead us into Q&A? Blake Fernandez: Thanks, Willie. As we enter the Q&A session, please limit yourself to two questions. For those with additional questions, please feel free to return to the queue. This will allow us to address questions from as many participants as possible in our available time this morning. The IR team will also be available after the call to address any additional questions you may have. Latif, would you please open the call for questions? Operator: Sir, as a reminder, to ask a question, you will need to press 11 on your telephone. Our first question comes from the line of Manav Gupta of UBS. Please go ahead, Manav. Sonia (for Manav Gupta): Hi. This is Sonia on for Manav. Good morning, and congrats on the quarter. When you think about assets in the Mid Con, there may be more one-time step-ups in synergy versus the Permian that could have more organic growth on top of that. So when we look at more bolt-on strategies and M&A, how do you factor in the sensitivity to basin-level growth? And in general, with basins, are you seeing more growth over time? Jeremy Goebel: Sandy, good morning. This is Jeremy. Here's what I would say. We take all that into consideration. And, candidly, as we've said before, we're a DCF shop, and we're looking for discounted cash flow over time and contributions. You have to look at the integrated network. So take the Mid Continent, for instance, which is an example. We have a lot of assets that touch a lot of other areas. So things that could impact Cushing or other downstream pipelines may have multiple touchpoints. So while the Permian has different resources, we look at them independently and use market fundamentals to drive an outload. Book of cash flows, and we use a discounted cash flow, and we have to beat our return thresholds, our cost of capital by 300 to 500 basis points as we've said. So we take all that into consideration. Not necessarily gonna say where our target area is right now, but we do look at everything and gotta hit our return threshold. And we certainly take a look at fundamentals and the multiple touchpoints we can have in each area. Sonia (for Manav Gupta): Got it. Thank you. And then on the macro side more, could you provide some color on real-time demand signals and any sign of slowdown or anything you're seeing on the refining or on the export side? Jeremy Goebel: Yes, ma'am. This is Jeremy again. Here's what I would say. I would follow the refiners. They've all talked about improving diesel demand and feel like it's strong. The last six months have felt a lot better than the prior six months from a demand perspective. We haven't seen the slowdown in demand most were expecting. And we expect that to continue. Willie mentioned that in his notes. So I'd say continue to follow the refiners and their demand. We're not seeing any issues from the downstream refining signals from crack spreads internationally and domestically. Differentials do move, and that's some indication, but over the last six-month period, we've seen strengthening demand, and we look forward to that continuing. Willie Chiang: Yes, Sonia. This is Willie. One comment I would add to that is that, you know, we're all watching a lot of uncertainty, certainly, over the last number of months and even years. Our view is continued short-term volatility, longer-term, more constructive. And where I would tell you our view is, despite a lot of the uncertainties, I have more confidence in the world and its ability to continue to grow than I did probably over the past year. So our views are pretty constructive, but I think there's gonna be a lot of volatility short term. Sonia (for Manav Gupta): Great. Thank you. Jeremy Goebel: Thank you. Operator: Thank you. Our next question comes from the line of Gabriel Moreen of Mizuho. Please go ahead, Gabriel. Gabriel Moreen: Hey. Good morning, everyone. Can I just ask on the BridgeTex deal and maybe talk about how that pipe is situated currently contract-wise and maybe how it would fit with the rest of your business? The value also seems to be a little bit, you know, changed from what it may have transacted out in the past. So if you can speak to that as well. Jeremy Goebel: Hi, Gabe. This is Jeremy. We're excited about the outcome consolidating that interest with ONEOK. I think from a contracting perspective, it's best to speak with them. But one thing is, as part of this transaction, we work on the cost structure going forward, as well as to consider commercial ways to fill the pipeline from a Plains perspective. To unite Plains and ONEOK's gathering systems to help keep the pipeline full. I think us working together will strengthen the positioning of the pipeline longer term. Gabriel Moreen: Thanks, Jeremy. And then maybe if I can ask in terms of some of the CapEx ins and outs on the growth CapEx raise here. For the lease connects in South Texas and the Permian, does that imply some degree of greater activity than you had been seeing, or is it just, you know, some degree of noise in terms of just things going on during the course of the year? Chris Chandler: Hey. Good morning, Gabe. It's Chris Chandler. I'll take this one. So, yeah, we have increased our 2025 investment CapEx guide to $475 million net to Plains. We've developed some new opportunities related to the Permian and Eagle Ford gathering, as you mentioned, in additional storage opportunities in the Permian. Some of this is basin growth-related, but some of it's frankly capturing business that we did not have before. They're good investments. They exceed our return thresholds, and they weren't in our original guidance. Hence being a new opportunity. So I hope that helps. Gabriel Moreen: Appreciate it. Thanks, Chris. Operator: Our next question comes from the line of Michael Blum of Wells Fargo. Michael Blum: Thanks. Good morning, everyone. Willie, I want to ask kind of a big picture question. You addressed some of this at the end of your remarks, but you know, you've made a big step here. You've exited the NGL business in Canada. You're now more or less solely focused on crude. So my question is, is the plan to simply execute the growth and capital return strategy as is, as you've been doing? Or could you see the company pivoting or diversifying into another area, whether that be expanding the crude footprint more expansively or into a whole different line of business? Just wanna get your sort of high-level thoughts there. Willie Chiang: Sure, Michael. Going to a pure play was not the objective. Right? Our objective is to create value for the unitholders however we possibly can. And so for us, you know, I've articulated this efficient growth strategy, and we've been executing on being able to unlock that. Now practically speaking, our business was roughly 80-85% crude, 15-20% NGL. By being able to do this transaction, it really catalyzes a lot of opportunities for us within Plains, which is why I spend a little more time in my prepared comments talking about that. One, we're gonna be able to redeploy approximately $3 billion. I can't say exactly how it's gonna be redeployed, but there's a number of opportunities that we've articulated on the bolt-on acquisitions, capital structure, opportunistic unit buybacks. And if you think about the cash flow that we've sold at a great valuation, we think we can do better redeploying it in the liquids business. When you think about how do you create value, it's all around synergies. And it's difficult to capture synergies if you don't have a strong position somewhere. So this is kind of a long-winded answer of saying, we're gonna stick to what we know. We've got size and scale. Really, a premier competitor in the industry, providing a lot of services for our customers. And we're gonna parlay on that and try to build even a stronger system kind of anchored on the platform of our constructive view of oil markets going forward. So if there are other opportunities that we can, whether it's in different basins or other commodities, we absolutely look at all those. We've got a very robust BD team. But practically speaking, I think you're gonna see more of it around the crude assets. And we feel we have a good runway of opportunities to look at. So, hopefully, that's helpful. Michael Blum: It is. So thank you for that. And then second, wanted to ask, and I might be nitpicking here, so apologies upfront. But on slide nine, the language on distribution growth changed a little bit. It used to say targeting multiyear sustainable distribution growth, and this latest slide deck says targeting sustainable distribution growth. So want to see if there's a shift in messaging there that we should be aware of. Thanks. Al Swanson: Hey, Michael. This is Al. No intended shift in messaging at all. We intend to grow our distribution over a multiyear period. So no intent there. Clearly, in the very interim time, Willie mentioned, we need to redeploy these proceeds. We fully expect to redeploy them in a way that's accretive to DCF, which would further enhance our ability to grow the dividend. Michael Blum: Thank you. Operator: Thank you. Our next question comes from the line of Spiro Dounis of Citi. Please go ahead, Spiro. Spiro Dounis: Thanks, operator. Good morning, gentlemen. I wanted to first ask about the 2025 guidance. It seems to suggest maybe a similar second half to the first half, if not maybe even a little bit lower. And so I'm curious, is that consistent with how you're viewing the back half of the year? And I guess, why would that be the case? It seemed like volumes are trending up kind of nicely this quarter. I know you mentioned some volatility out there, so maybe it's just that. But you've also got the contribution from some bolt-ons. So just looking to get some color there in the back half. Jeremy Goebel: Good morning, Spiro. It's Jeremy. Just remember, we have the contract roll-offs of Cactus II, Cactus I, and Sunrise in the second half of the year, all consistent with guidance. So those roll off of the contract rates, all those volumes have been recontracted. It's a function of rate being lower. So you had those contributions in the first half. You're gonna have the growing production, the FERC escalator, and other pieces contributing to backfill that. So while it may look flat, you backfilled some of the roll-off of the contracts with growth. Spiro Dounis: Got it. It's helpful, Jeremy. Thank you. Second question, just maybe going to the bolt-on strategy again. I guess, we think about your ability to keep doing these bolt-ons for the rest of the year? Pending that NGL sale? I don't imagine you want to pre-spend that $3 billion. But as you do think about getting those proceeds, you could obviously do a lot more than a bolt-on with that $3 billion. So I guess I'm just curious how you're weighing the ability or maybe the potential to do something larger? Willie Chiang: Well, Spiro, it's very difficult to time all these things, as you well know. Which is why I mentioned our robust BD team looking at a lot of things. What I would tell you is that's the other reason of our financial flex creating a lot of capacity on our balance sheet. To be able to absorb some of that. So where I think we're positioned, where we are positioned at is look at a lot of opportunities, and as they come up, we're trying to put ourselves in the best position to be able to execute on them, whether they're small, medium, or even large. So I'll leave it at that. Spiro Dounis: Helpful as always. Thank you, gentlemen. Have a good weekend. Operator: Thank you. Next question comes from the line of Sunil Sibal of Seaport Global. Please go ahead, Sunil. Sunil Sibal: Yes. Hi. Good morning. And most of my bigger questions have been hit, but I just wanted to clarify a couple of things. On the BridgeTex, so you're buying that as part of the ORIX JV? Jeremy Goebel: Correct. Sunil, this is Jeremy. No. That's independent. That is Plains purchasing it. We're an existing owner in the JV, and ONEOK and Plains are buying in proportionate to their interest in the pipeline. Sunil Sibal: Okay. Understood. And then in terms of the overall positioning, seems like you're still retaining some US NGL business. If that's correct, you know, is there a bigger strategy there, or how should we think about, you know, that piece of the business going forward? Jeremy Goebel: Sunil, that's very minor and relative to the entire asset base. Those were smaller contributors. And from a tax perspective and operations perspective, it made sense for us to and we'll look to monetize those at a later date. But I would say that's not part of a larger strategy. You'd see us more likely to divest those than retain them. Sunil Sibal: Got it. Thank you. Operator: Thank you. Our next question comes from the line of John Mackay of Goldman Sachs. Please go ahead, John. John Mackay: Hey, guys. Thank you for the time. Maybe just wanted to touch on the CapEx piece again this year. I mean, how much of that increase do you think is maybe actually a pickup in producer activity overall relative to what you're expecting, or maybe that's more of just a, you know, you guys had some commercial success, but it's not necessarily pointing to kind of a broader macro theme. And then maybe just taking that neck looking forward, you know, why shouldn't we think of the kind of run rate CapEx number moving up a little bit if you guys were able to get these wins? Thanks. Chris Chandler: John, it's Chris Chandler. I'll take that. It's really a combination of all the above. The factors that you mentioned. You know, there's certainly new opportunities that we didn't anticipate coming into the year, and those played a role. I'd also point out our continued bolt-on acquisition strategy brings new opportunities for synergy capture around those assets where we didn't have operations before. So it's really kind of an all of the above. When you think in 2026 on investment capital spend, we're obviously not giving guidance at this point in time. We'll do that in early 2026. You can look at how much we're spending on NGL this year, which is above average compared to prior years. So, you know, we would expect that to step down when the NGL sale to Keyera closes. But we continue to be successful identifying new opportunities. So, you know, in respect of identifying and capturing those projects that meet our investment threshold, you know, we'd love to grow CapEx modestly because of the good opportunities that we're able to capture. Blake Fernandez: Hey, John. It's Blake. If you don't mind real quick, I would add, just as a reminder, the 2025 CapEx program includes about $30 or $40 million of deferrals from last year. So that might help you think about the progression into 2026. John Mackay: Makes sense. That's helpful. And then maybe just going back to your comments on the retained NGL assets, I think your answer before made sense. I understand they're small. But are you guys able just to quantify for us again what that looks like right now? And then maybe is that reflecting kind of a 2025 spread environment, or is that a pretty good whatever you share, is that a pretty good number going forward? Jeremy Goebel: I can put that in the $10 to $15 million of EBITDA category. And just from a valuation standpoint, think of the $200 million range. John Mackay: That's helpful. I appreciate that. Thank you guys for the time. Operator: Thanks, John. Our next question comes from the line of Brandon Bingham of Scotiabank. Brandon Bingham: Hi. Good morning. Thanks for taking the questions here. Just one quick one for me. I know it says in the slides that you still expect to come in towards the lower end of the EBITDA guide, but things have improved even just slightly versus all the one Q chaos. So just kind of curious where you see that as we move forward throughout the year and whether or not there's a higher likelihood now that we could be back towards the midpoint. Al Swanson: This is Al. I'll take a shot at it. I think the wording should have been lower half, so we weren't trying to point at the low end by any means if that's what the question was. And we believe the lower half would be how we're trying to guide it. We're not trying to guide you to the midpoint or the bottom end, but just the lower half. Clearly, there's a period of time here. Prices have been fairly volatile. I think crude oil today is roughly where we articulated the range to be a quarter ago in the $60-65 range. I think we're kind of at the high end of that now. So more time to come with regard to that, but we would kind of point you to the lower half, not the lower end. Brandon Bingham: Okay. Apologies. I might have misread. But thank you. Operator: I would now like to turn the conference back to management for closing remarks. Willie Chiang: Latif, thanks, and thanks to everyone for joining us today. We'll look forward to giving you more updates, and we'll see you on the road. Have a great day and a great weekend. Operator: This concludes today's conference call. Thank you for participating. You may now disconnect. Where to invest $1,000 right now When our analyst team has a stock tip, it can pay to listen. After all, Stock Advisor's total average return is 1,047%* — a market-crushing outperformance compared to 181% for the S&P 500. They just revealed what they believe are the 10 best stocks for investors to buy right now, available when you join Stock Advisor. See the stocks » *Stock Advisor returns as of August 4, 2025 This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. Parts of this article were created using Large Language Models (LLMs) based on The Motley Fool's insights and investing approach. It has been reviewed by our AI quality control systems. Since LLMs cannot (currently) own stocks, it has no positions in any of the stocks mentioned. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability.
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Plains All American Reports Second-Quarter 2025 Results
HOUSTON, Aug. 08, 2025 (GLOBE NEWSWIRE) -- Plains All American Pipeline, L.P. (Nasdaq: PAA) and Plains GP Holdings (Nasdaq: PAGP) today reported solid second-quarter 2025 results and provided the following highlights: Second-Quarter Results Reported net income attributable to PAA of $210 million and net cash provided by operating activities of $694 million Delivered Adjusted EBITDA attributable to PAA of $672 million Exited the quarter with 3.3x leverage ratio, toward the low-end of our target range of 3.25x - 3.75x Highlights and Recent Announcements Executed agreements to divest substantially all of our NGL business for total cash consideration of approximately $5.15 billion CAD ($3.75 billion USD) with expected closing first quarter 2026 pending regulatory approval NGL sale proceeds (~$3.0 billion net USD) will be prioritized toward bolt-on M&A, preferred unit repurchases, and opportunistic common unit repurchases On July 22, 2025, Plains acquired an additional 20% interest in BridgeTex Pipeline Company, LLC, bringing PAA's total interest to 40% 'We continue to advance our strategic initiatives and delivered solid second-quarter performance in a volatile macro environment,' said Willie Chiang, Chairman, CEO and President. 'Our previously announced NGL divestiture is expected to close in the first quarter of 2026 and will improve our free cash durability, provide substantial financial flexibility and drive opportunities to streamline the business. Separately, we continue to execute on our bolt-on acquisition opportunity set by acquiring an incremental interest in the BridgeTex Pipeline joint venture, which further strengthens our Permian footprint. We remain well-positioned and highly focused on additional bolt-ons and optimizing our crude oil focused asset base in a capital disciplined manner while continuing to return cash to unitholders.' Financial Reporting Considerations for Pending Sale of Canadian NGL BusinessOn June 17, 2025, we entered into a definitive agreement to sell substantially all of our NGL business in Canada (the 'Canadian NGL Business') to Keyera Corp. This transaction is expected to close in the first quarter of 2026 and is subject to the satisfaction or waiver of customary closing conditions, including receipt of regulatory approvals. While we will divest the Canadian NGL Business as part of the transaction, we will retain substantially all NGL assets in the United States and will also retain all crude oil assets in Canada. We have determined that the operations of the Canadian NGL Business meet the criteria for classification as held for sale and presentation as discontinued operations and have applied these changes retrospectively to all periods presented. Results throughout this release specify if they are presented from continuing operations (which exclude the results of the Canadian NGL Business) and/or discontinued operations. Plains All American Pipeline Summary Financial Information (unaudited)(in millions, except per unit data) Three Months EndedJune 30, % Six Months EndedJune 30, % 2025 2024 Change 2025 2024 Change Net income attributable to PAA (2) $ 210 $ 250 (16 )% $ 653 $ 515 27 % Diluted net income per common unit $ 0.21 $ 0.26 (19 )% $ 0.70 $ 0.55 27 % Diluted weighted average common units outstanding 703 701 — % 704 701 — % Net cash provided by operating activities $ 694 $ 653 6 % $ 1,333 $ 1,072 24 % Distribution per common unit declared for the period $ 0.3800 $ 0.3175 20 % $ 0.7600 $ 0.6350 20 % Three Months EndedJune 30, % Six Months EndedJune 30, % 2025 2024 Change 2025 2024 Change Adjusted net income attributable to PAA (2) $ 312 $ 288 8 % $ 687 $ 642 7 % Diluted adjusted net income per common unit $ 0.36 $ 0.31 16 % $ 0.75 $ 0.72 4 % Adjusted EBITDA $ 812 $ 807 1 % $ 1,693 $ 1,654 2 % Adjusted EBITDA attributable to PAA (2) $ 672 $ 674 — % $ 1,426 $ 1,391 3 % Implied DCF per common unit and common unit equivalent $ 0.66 $ 0.58 14 % $ 1.32 $ 1.25 6 % Adjusted Free Cash Flow (4) $ 348 $ 411 (15 )% $ 40 $ 480 (92 )% Adjusted Free Cash Flow after Distributions (4) $ 28 $ 125 (78 )% $ (612 ) $ (92 ) ** Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) (4) $ 342 $ 421 (19 )% $ 174 $ 681 (74 )% Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) (4) $ 22 $ 135 (84 )% $ (478 ) $ 109 ** ______________________________ ** Indicates that variance as a percentage is not meaningful. (1) Includes results from continuing operations and discontinued operations for all periods presented. See the tables attached hereto for additional information. (2) Excludes amounts attributable to noncontrolling interests in the Plains Oryx Permian Basin LLC (the 'Permian JV'), Cactus II Pipeline LLC and Red River Pipeline LLC joint ventures. (3) See the section of this release entitled 'Non-GAAP Financial Measures and Selected Items Impacting Comparability' and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods. (4) The six months ended June 30, 2025 includes the impact of a net cash outflow of $681 million for bolt-on acquisitions. Disaggregation of Adjusted EBITDA by Product (1) (2) (unaudited)(in millions) Adjusted EBITDA from Crude Oil Adjusted EBITDA from NGL Three Months Ended June 30, 2025 $ 580 $ 87 Three Months Ended June 30, 2024 $ 576 $ 94 Adjusted EBITDA from Crude Oil Adjusted EBITDA from NGL Six Months Ended June 30, 2025 $ 1,140 $ 276 Six Months Ended June 30, 2024 $ 1,130 $ 253 ______________________________ ** Indicates that variance as a percentage is not meaningful. (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) See the section of this release entitled 'Non-GAAP Financial Measures and Selected Items Impacting Comparability' and the tables attached hereto for information regarding our Non-GAAP financial measures, including their reconciliation to the most directly comparable measures as reported in accordance with GAAP, and certain selected items that PAA believes impact comparability of financial results between reporting periods. Second-quarter 2025 Adjusted EBITDA from Crude Oil was in line with comparable 2024 results. Favorable results in the 2025 period from (i) higher tariff volumes on our pipelines, (ii) tariff escalations and (iii) contributions from recently completed bolt-on acquisitions were largely offset by (iv) fewer market opportunities and (v) lower commodity prices. Second-quarter 2025 Adjusted EBITDA from NGL decreased 7% versus comparable 2024 results primarily due to lower iso-to-normal butane spread benefits in the second quarter of 2025. Plains GP HoldingsPAGP owns an indirect non-economic controlling interest in PAA's general partner and an indirect limited partner interest in PAA. As the control entity of PAA, PAGP consolidates PAA's results into its financial statements, which is reflected in the condensed consolidating balance sheet and income statement tables attached hereto. PAA and PAGP will hold a joint conference call at 9:00 a.m. CT on Friday, August 8, 2025 to discuss second-quarter performance and related items. To access the internet webcast, please go to Alternatively, the webcast can be accessed on our website at Following the live webcast, an audio replay will be available on our website and will be accessible for a period of 365 days. Slides will be posted prior to the call at the above referenced website. To supplement our financial information presented in accordance with GAAP, management uses additional measures known as 'non-GAAP financial measures' in its evaluation of past performance and prospects for the future and to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. The primary additional measures used by management are Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied Distributable Cash Flow ('DCF'), Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions. Our definition and calculation of certain non-GAAP financial measures may not be comparable to similarly-titled measures of other companies. Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF and certain other non-GAAP financial performance measures are reconciled to Net Income, and Adjusted Free Cash Flow, Adjusted Free Cash Flow after Distributions and certain other non-GAAP financial liquidity measures are reconciled to Net Cash Provided by Operating Activities (the most directly comparable measures as reported in accordance with GAAP) for the historical periods presented in the tables attached to this release, and should be viewed in addition to, and not in lieu of, our Condensed Consolidated Financial Statements and accompanying notes. In addition, we encourage you to visit our website at (in particular the section under 'Financial Information' entitled 'Non-GAAP Reconciliations' within the Investor Relations tab), which presents a reconciliation of our commonly used non-GAAP and supplemental financial measures. We do not reconcile non-GAAP financial measures on a forward-looking basis as it is impractical to do so without unreasonable effort. Non-GAAP Financial Performance MeasuresAdjusted EBITDA is defined as earnings from continuing operations and discontinued operations before (i) interest expense, (ii) income tax (expense)/benefit from continuing operations and discontinued operations, (iii) depreciation and amortization (including our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, of unconsolidated entities) from continuing operations and discontinued operations, (iv) gains and losses on asset sales, asset impairments and other, net from continuing operations and discontinued operations, (v) gains on investments in unconsolidated entities, net and (vi) interest income on promissory notes by and among certain Plains entities, and (vii) adjusted for certain selected items impacting comparability. Adjusted EBITDA attributable to PAA excludes the portion of Adjusted EBITDA that is attributable to noncontrolling interests. Adjusted EBITDA disaggregated by product (e.g., Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL) exclude amounts related to Other income/(expense). Management believes that the presentation of Adjusted EBITDA, Adjusted EBITDA attributable to PAA and Implied DCF provides useful information to investors regarding our performance and results of operations because these measures, when used to supplement related GAAP financial measures, (i) provide additional information about our operating performance and ability to fund distributions to our unitholders through cash generated by our operations and (ii) provide investors with the same financial analytical framework upon which management bases financial, operational, compensation and planning/budgeting decisions. We also present these and additional non-GAAP financial measures, including adjusted net income attributable to PAA and basic and diluted adjusted net income per common unit, as they are measures that investors, rating agencies and debt holders have indicated are useful in assessing us and our results of operations. These non-GAAP financial performance measures may exclude, for example, (i) charges for obligations that are expected to be settled with the issuance of equity instruments, (ii) gains and losses on derivative instruments that are related to underlying activities in another period (or the reversal of such adjustments from a prior period), gains and losses on derivatives that are either related to investing activities (such as the purchase of linefill) or purchases of long-term inventory, and inventory valuation adjustments, as applicable, (iii) long-term inventory costing adjustments, (iv) items that are not indicative of our operating results and/or (v) other items that we believe should be excluded in understanding our operating performance. These measures may be further adjusted to include amounts related to deficiencies associated with minimum volume commitments whereby we have billed the counterparties for their deficiency obligation and such amounts are recognized as deferred revenue in 'Other current liabilities' in our Condensed Consolidated Financial Statements. We also adjust for amounts billed by our equity method investees related to deficiencies under minimum volume commitments. Such amounts are presented net of applicable amounts subsequently recognized into revenue. Furthermore, the calculation of these measures contemplates tax effects as a separate reconciling item, where applicable. We have defined all such items as 'selected items impacting comparability.' Due to the nature of the selected items, certain selected items impacting comparability may impact certain non-GAAP financial measures, referred to as adjusted results, but not impact other non-GAAP financial measures. We do not necessarily consider all of our selected items impacting comparability to be non-recurring, infrequent or unusual, but we believe that an understanding of these selected items impacting comparability is material to the evaluation of our operating results and prospects. Although we present selected items impacting comparability that management considers in evaluating our performance, you should also be aware that the items presented do not represent all items that affect comparability between the periods presented. Variations in our operating results are also caused by changes in volumes, prices, exchange rates, mechanical interruptions, acquisitions, divestitures, investment capital projects and numerous other factors. These types of variations may not be separately identified in this release, but will be discussed, as applicable, in management's discussion and analysis of operating results in our Quarterly Report on Form 10-Q. Non-GAAP Financial Liquidity MeasuresManagement uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow is defined as Net Cash Provided by Operating Activities, less Net Cash Provided by/(Used in) Investing Activities, which primarily includes acquisition, investment and maintenance capital expenditures, investments in unconsolidated entities and related party notes and the impact from the purchase and sale of linefill, net of proceeds from the sales of assets and further impacted by distributions to and contributions from noncontrolling interests and proceeds from the issuance of related party notes. Adjusted Free Cash Flow is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions. We also present these measures and additional non-GAAP financial liquidity measures as they are measures that investors have indicated are useful. We present Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) for use in assessing our underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is defined as Adjusted Free Cash Flow excluding the impact of 'Changes in assets and liabilities, net of acquisitions' on our Condensed Consolidated Statements of Cash Flows. Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) is further reduced by cash distributions paid to our preferred and common unitholders to arrive at Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities). Non-GAAP Financial Measures and Discontinued OperationsManagement believes that the presentation of certain Non-GAAP financial performance measures, such as Adjusted EBITDA, Adjusted EBITDA attributable to PAA, Implied DCF, Adjusted Net Income attributable to PAA, Adjusted Net Income per Common Unit, Adjusted EBITDA from Crude Oil and Adjusted EBITDA from NGL, and certain Non-GAAP financial liquidity measures, such as Adjusted Free Cash Flow and Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities), on a consolidated basis (e.g., the aggregate of continuing operations and discontinued operations) provides more relevant and useful information regarding our performance and results of operations than presenting such metrics only on a continuing operations or discontinued operations basis. In addition, as the potential sale of the Canadian NGL Business is not anticipated to close until the first quarter of 2026, management continues to view the Canadian NGL Business as a component of our overall company performance and ability to fund distributions to our unitholders in the near term. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS(in millions, except per unit data) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 REVENUES $ 10,642 $ 12,757 $ 22,119 $ 24,396 COSTS AND EXPENSES Purchases and related costs 9,758 11,838 20,277 22,543 Field operating costs 286 280 585 553 General and administrative expenses 82 79 168 160 Depreciation and amortization 235 226 466 449 Losses on asset sales, net 42 2 29 3 Total costs and expenses 10,403 12,425 21,525 23,708 OPERATING INCOME 239 332 594 688 OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 94 106 196 201 Gain on investments in unconsolidated entities, net — — 31 — Interest expense, net (1) (133 ) (111 ) (260 ) (205 ) Other income, net (1) 31 23 57 18 INCOME FROM CONTINUING OPERATIONS BEFORE TAX 231 350 618 702 Current income tax expense from continuing operations (1 ) (52 ) (6 ) (68 ) Deferred income tax (expense)/benefit from continuing operations (3 ) — (5 ) 5 INCOME FROM CONTINUING OPERATIONS, NET OF TAX 227 298 607 639 INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX 70 32 206 42 NET INCOME 297 330 813 681 Net income attributable to noncontrolling interests (87 ) (80 ) (160 ) (166 ) NET INCOME ATTRIBUTABLE TO PAA $ 210 $ 250 $ 653 $ 515 NET INCOME PER COMMON UNIT: Net income allocated to common unitholders — Basic and Diluted: Continuing operations $ 80 $ 148 $ 287 $ 340 Discontinued operations 70 32 206 42 Net income allocated to common unitholders — Basic and Diluted $ 150 $ 180 $ 493 $ 382 Basic and diluted weighted average common units outstanding 703 701 704 701 Basic and diluted net income per common unit: Continuing operations $ 0.11 $ 0.21 $ 0.41 $ 0.49 Discontinued operations $ 0.10 $ 0.05 $ 0.29 $ 0.06 Basic and diluted net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 ___________________________________ (1) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. 'Interest expense, net' and 'Other income, net' each include $23 million and $43 million for the three and six months ended June 30, 2025, respectively, and $15 million for the three and six months ended June 30, 2024 related to interest on such related party promissory notes. These amounts offset and do not impact Net Income or Non-GAAP metrics such as Adjusted EBITDA, Implied DCF and Adjusted Free Cash Flow. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED BALANCE SHEET DATA(in millions) June 30,2025 December 31,2024 ASSETS Current assets (including cash and cash equivalents of $459 and $348, respectively) (1) $ 4,688 $ 4,802 Property and equipment, net 14,177 13,446 Investments in unconsolidated entities 2,709 2,811 Intangible assets, net 1,636 1,677 Linefill 940 904 Long-term operating lease right-of-use assets, net 182 189 Long-term inventory 234 242 Long-term assets of discontinued operations 2,482 2,349 Other long-term assets, net 107 142 Total assets $ 27,155 $ 26,562 LIABILITIES AND PARTNERS' CAPITAL Current liabilities (2) $ 4,679 $ 4,950 Senior notes, net 8,133 7,141 Other long-term debt, net 71 70 Long-term operating lease liabilities 190 192 Long-term liabilities of discontinued operations 598 576 Other long-term liabilities and deferred credits 535 537 Total liabilities 14,206 13,466 Partners' capital excluding noncontrolling interests 9,706 9,813 Noncontrolling interests 3,243 3,283 Total partners' capital 12,949 13,096 Total liabilities and partners' capital $ 27,155 $ 26,562__________________________________ (1) Includes current assets of discontinued operations of $385 million and $415 million as of June 30, 2025 and December 31, 2024, respectively. (2) Includes current liabilities of discontinued operations of $313 million and $350 million as of June 30, 2025 and December 31, 2024, respectively. DEBT CAPITALIZATION RATIOS (1)(in millions, except percentages) June 30,2025 December 31,2024 Short-term debt $ 476 $ 408 Long-term debt 8,206 7,213 Total debt $ 8,682 $ 7,621 Long-term debt $ 8,206 $ 7,213 Partners' capital excluding noncontrolling interests 9,706 9,813 Total book capitalization excluding noncontrolling interests ('Total book capitalization') $ 17,912 $ 17,026 Total book capitalization, including short-term debt $ 18,388 $ 17,434 Long-term debt-to-total book capitalization 46 % 42 % Total debt-to-total book capitalization, including short-term debt 47 % 44 %_______________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME PER COMMON UNIT(in millions, except per unit data) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Basic and Diluted Net Income per Common Unit Continuing Operations: Income from continuing operations, net of tax $ 227 $ 298 $ 607 $ 639 Net income attributable to noncontrolling interests (87 ) (80 ) (160 ) (166 ) Net income from continuing operations attributable to PAA $ 140 $ 218 $ 447 $ 473 Distributions to Series A preferred unitholders (36 ) (44 ) (75 ) (88 ) Distributions to Series B preferred unitholders (18 ) (19 ) (35 ) (39 ) Amounts allocated to participating securities (7 ) (8 ) (9 ) (9 ) Impact from repurchase of Series A preferred units (1) — — (43 ) — Other 1 1 2 3 Net income from continuing operations allocated to common unitholders - Basic and Diluted (2) $ 80 $ 148 $ 287 $ 340 Discontinued Operations: Net income from discontinued operations allocated to common unitholders - Basic and Diluted (3) $ 70 $ 32 $ 206 $ 42 Net income allocated to common unitholders — Basic and Diluted $ 150 $ 180 $ 493 $ 382 Basic and diluted weighted average common units outstanding (4) (5) 703 701 704 701 Basic and diluted net income per common unit: Continuing operations $ 0.11 $ 0.21 $ 0.41 $ 0.49 Discontinued operations $ 0.10 $ 0.05 $ 0.29 $ 0.06 Basic and diluted net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 _______________________________ (1) We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of net income allocated to common unitholders. (2) We calculate net income from continuing operations allocated to common unitholders based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (3) Net income from discontinued operations allocated to common unitholders is Income from discontinued operations, net of tax as presented on our Condensed Consolidated Statements of Operations. (4) The possible conversion of our Series A preferred units was excluded from the calculation of diluted net income per common unit for each of the three and six months ended June 30, 2025 and 2024 as the effect was antidilutive. (5) Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATED CASH FLOW DATA(in millions) Six Months EndedJune 30, 2025 2024 CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 813 $ 681 Reconciliation of net income to net cash provided by operating activities: Income from discontinued operations, net of tax (206 ) (42 ) Depreciation and amortization 466 449 Losses on asset sales, net 29 3 Deferred income tax expense/(benefit) 5 (5 ) (Gain)/loss on foreign currency revaluation 4 (15 ) Settlement of terminated interest rate hedging instruments — 57 Equity earnings in unconsolidated entities (196 ) (201 ) Distributions on earnings from unconsolidated entities 256 250 Gain on investments in unconsolidated entities, net (31 ) — Other 32 37 Changes in assets and liabilities, net of acquisitions (140 ) (222 ) Cash provided by operating activities - continuing operations 1,032 992 Cash provided by operating activities - discontinued operations 301 80 Net cash provided by operating activities 1,333 1,072 CASH FLOWS FROM INVESTING ACTIVITIES Cash used in investing activities - continuing operations (1,317 ) (357 ) Cash used in investing activities - discontinued operations (106 ) (61 ) Net cash used in investing activities (1) (2) (1,423 ) (418 ) CASH FLOWS FROM FINANCING ACTIVITIES Net cash provided by/(used in) financing activities (1) 182 (545 ) Effect of translation adjustment - continuing operations 8 (5 ) Effect of translation adjustment - discontinued operations 11 (1 ) Net increase in cash and cash equivalents and restricted cash 111 103 Cash and cash equivalents and restricted cash, beginning of period 348 450 Cash and cash equivalents and restricted cash, end of period $ 459 $ 553 _______________________________ (1) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. For the six months ended June 30, 2025, 'Net cash used in investing activities' includes a cash outflow of approximately $330 million associated with our investment in related party notes. An equal and offsetting cash inflow associated with our issuance of related party notes is included in 'Net cash provided by/(used in) financing activities.' (2) The 2025 period includes a net cash outflow of $681 million for bolt-on acquisitions. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) CAPITAL EXPENDITURES (1)(in millions) Net to PAA (2) Consolidated Three Months EndedJune 30, Six Months EndedJune 30, Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 2025 2024 2025 2024 Investment capital expenditures: Crude Oil $ 126 $ 42 $ 215 $ 107 $ 160 $ 58 $ 280 $ 148 NGL (3) 27 23 68 37 27 23 68 37 Total Investment capital expenditures 153 65 283 144 187 81 348 185 Total Maintenance capital expenditures (4) 58 56 97 109 64 61 105 118 Total Investment and Maintenance capital expenditures $ 211 $ 121 $ 380 $ 253 $ 251 $ 142 $ 453 $ 303_________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Excludes expenditures attributable to noncontrolling interests. (3) See the 'Discontinued Operations Detail' section for amounts attributable to discontinued operations. (4) See the 'Selected Financial Data by NGL' section for amounts attributable to discontinued operations. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIES FINANCIAL SUMMARY (unaudited) NON-GAAP RECONCILIATIONS(in millions, except per unit and ratio data) Computation of Basic and Diluted Adjusted Net Income Per Common Unit (1) (2) : Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Basic and Diluted Adjusted Net Income per Common Unit Net income attributable to PAA $ 210 $ 250 $ 653 $ 515 Selected items impacting comparability - Adjusted net income attributable to PAA (3) 102 38 34 127 Adjusted net income attributable to PAA $ 312 $ 288 $ 687 $ 642 Distributions to Series A preferred unitholders (36 ) (44 ) (75 ) (88 ) Distributions to Series B preferred unitholders (18 ) (19 ) (35 ) (39 ) Amounts allocated to participating securities (7 ) (8 ) (9 ) (10 ) Impact from repurchase of Series A preferred units (4) — — (43 ) — Other 1 1 2 3 Adjusted net income allocated to common unitholders $ 252 $ 218 $ 527 $ 508 Basic and diluted weighted average common units outstanding (5) (6) 703 701 704 701 Basic and diluted adjusted net income per common unit $ 0.36 $ 0.31 $ 0.75 $ 0.72 ____________________________________ (1) We calculate adjusted net income allocated to common unitholders based on the distributions pertaining to the current period's net income. After adjusting for the appropriate period's distributions, the remaining undistributed earnings or excess distributions over earnings, if any, are allocated to the common unitholders and participating securities in accordance with the contractual terms of our partnership agreement in effect for the period and as further prescribed under the two-class method. (2) Includes results from continuing operations and discontinued operations for all periods presented. (3) See the 'Selected Items Impacting Comparability' table for additional information. (4) We repurchased approximately 12.7 million Series A preferred units on January 31, 2025. The difference between the cash we paid for the repurchase of such units and their carrying value on our balance sheet is considered a return to Series A preferred unitholders for the calculation of adjusted net income allocated to common unitholders. (5) The possible conversion of our Series A preferred units was excluded from the calculation of diluted adjusted net income per common unit for each of the three and six months ended June 30, 2025 and 2024 as the effect was antidilutive. (6) Our equity-indexed compensation plan awards that contemplate the issuance of common units are considered potentially dilutive unless (i) they become vested only upon the satisfaction of a performance condition and (ii) that performance condition has yet to be satisfied. Equity-indexed compensation plan awards that are deemed to be dilutive are reduced by a hypothetical common unit repurchase based on the remaining unamortized fair value, as prescribed by the treasury stock method in guidance issued by the FASB. Net Income Per Common Unit to Adjusted Net Income Per Common Unit Reconciliation (1): Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Basic and diluted net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 Selected items impacting comparability per common unit (2) 0.15 0.05 0.05 0.17 Basic and diluted adjusted net income per common unit $ 0.36 $ 0.31 $ 0.75 $ 0.72____________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) See the 'Selected Items Impacting Comparability' and the 'Computation of Basic and Diluted Adjusted Net Income Per Common Unit' tables for additional information. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation: Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Net income (1) $ 297 $ 330 $ 813 $ 681 Interest expense, net of certain items (2) 110 96 217 190 Income tax expense from continuing operations 4 52 11 63 Income tax expense from discontinued operations 26 10 69 14 Depreciation and amortization from continuing operations 235 226 466 449 Depreciation and amortization from discontinued operations 27 31 57 62 Losses on asset sales, net from continuing operations 42 2 29 3 (Gains)/losses on asset sales, net from discontinued operations 13 (1 ) 13 (2 ) Gain on investments in unconsolidated entities, net — — (31 ) — Depreciation and amortization of unconsolidated entities (3) 20 17 40 37 Selected items impacting comparability - Adjusted EBITDA (1) (4) 38 44 9 157 Adjusted EBITDA (1) $ 812 $ 807 $ 1,693 $ 1,654 Adjusted EBITDA attributable to noncontrolling interests (140 ) (133 ) (267 ) (263 ) Adjusted EBITDA attributable to PAA (1) $ 672 $ 674 $ 1,426 $ 1,391 Adjusted EBITDA (1) $ 812 $ 807 $ 1,693 $ 1,654 Interest expense, net of certain non-cash and other items (5) (107 ) (91 ) (211 ) (180 ) Maintenance capital from continuing operations (44 ) (43 ) (77 ) (90 ) Maintenance capital from discontinued operations (20 ) (18 ) (28 ) (28 ) Investment capital of noncontrolling interests (6) (33 ) (17 ) (64 ) (41 ) Current income tax expense from continuing operations (1 ) (52 ) (6 ) (68 ) Current income tax expense from discontinued operations (14 ) (17 ) (54 ) (55 ) Distributions from unconsolidated entities in excess of/(less than) adjusted equity earnings (7) 22 (5 ) 19 7 Distributions to noncontrolling interests (8) (97 ) (97 ) (229 ) (198 ) Implied DCF (1) $ 518 $ 467 $ 1,043 $ 1,001 Preferred unit distributions paid (8) (53 ) (63 ) (117 ) (127 ) Implied DCF Available to Common Unitholders (1) $ 465 $ 404 $ 926 $ 874 Weighted Average Common Units Outstanding 703 701 704 701 Weighted Average Common Units and Common Unit Equivalents 761 772 764 772 Implied DCF per Common Unit (1) (9) $ 0.66 $ 0.58 $ 1.32 $ 1.25 Implied DCF per Common Unit and Common Unit Equivalent (1) (10) $ 0.66 $ 0.58 $ 1.32 $ 1.25 Cash Distribution Paid per Common Unit $ 0.3800 $ 0.3175 $ 0.7600 $ 0.6350 Common Unit Cash Distributions (8) $ 267 $ 223 $ 535 $ 445 Common Unit Distribution Coverage Ratio (1) 1.74x 1.81x 1.73x 1.96x Implied DCF Excess (1) $ 198 $ 181 $ 391 $ 429 _____________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Represents 'Interest expense, net' as reported on our Condensed Consolidated Statements of Operations, net of interest income associated with promissory notes by and among certain Plains entities. (3) Adjustment to exclude our proportionate share of depreciation and amortization expense (including write-downs related to cancelled projects and impairments) of unconsolidated entities. (4) See the 'Selected Items Impacting Comparability' table for additional information. (5) Amount excludes certain non-cash items impacting interest expense such as amortization of debt issuance costs and terminated interest rate swaps and is net of interest income associated with promissory notes by and among certain Plains entities. (6) Investment capital expenditures attributable to noncontrolling interests that reduce Implied DCF available to PAA common unitholders. (7) Comprised of cash distributions received from unconsolidated entities less equity earnings in unconsolidated entities (adjusted for our proportionate share of depreciation and amortization, including write-downs related to cancelled projects and impairments, and selected items impacting comparability of unconsolidated entities). (8) Cash distributions paid during the period presented. (9) Implied DCF Available to Common Unitholders for the period divided by the weighted average common units outstanding for the period. (10) Implied DCF Available to Common Unitholders for the period, adjusted for Series A preferred unit cash distributions paid, divided by the weighted average common units and common unit equivalents outstanding for the period. Our Series A preferred units are convertible into common units, generally on a one-for-one basis and subject to customary anti-dilution adjustments, in whole or in part, subject to certain minimum conversion amounts. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) Net Income Per Common Unit to Implied DCF Per Common Unit and Common Unit Equivalent Reconciliation (1): Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Basic net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 Reconciling items per common unit (2) (3) 0.45 0.32 0.62 0.70 Implied DCF per common unit $ 0.66 $ 0.58 $ 1.32 $ 1.25 Basic net income per common unit $ 0.21 $ 0.26 $ 0.70 $ 0.55 Reconciling items per common unit and common unit equivalent (2) (4) 0.45 0.32 0.62 0.70 Implied DCF per common unit and common unit equivalent $ 0.66 $ 0.58 $ 1.32 $ 1.25______________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Represents adjustments to Net Income to calculate Implied DCF Available to Common Unitholders. See the 'Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation' table for additional information. (3) Based on weighted average common units outstanding for the periods of 703 million, 701 million, 704 million and 701 million, respectively. (4) Based on weighted average common units outstanding for the periods, as well as weighted average Series A preferred units outstanding of 58 million, 71 million, 60 million and 71 million for the periods presented, respectively. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) Net Cash Provided by Operating Activities to Non-GAAP Financial Liquidity Measures Reconciliation: Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Net cash provided by operating activities (1) $ 694 $ 653 $ 1,333 $ 1,072 Adjustments to reconcile Net cash provided by operating activities to Adjusted Free Cash Flow: Net cash used in investing activities (1) (2) (3) (274 ) (157 ) (1,423 ) (418 ) Cash contributions from noncontrolling interests 25 12 29 24 Cash distributions paid to noncontrolling interests (4) (97 ) (97 ) (229 ) (198 ) Proceeds from the issuance of related party notes (2) — — 330 — Adjusted Free Cash Flow (1) (5) $ 348 $ 411 $ 40 $ 480 Cash distributions (6) (320 ) (286 ) (652 ) (572 ) Adjusted Free Cash Flow after Distributions (1) (5) (7) $ 28 $ 125 $ (612 ) $ (92 ) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Adjusted Free Cash Flow (1) (5) $ 348 $ 411 $ 40 $ 480 Changes in assets and liabilities, net of acquisitions (1) (8) (6 ) 10 134 201 Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) (1) (9) $ 342 $ 421 $ 174 $ 681 Cash distributions (6) (320 ) (286 ) (652 ) (572 ) Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) (1) (9) $ 22 $ 135 $ (478 ) $ 109 _________________________________ (1) Includes results from continuing operations and discontinued operations for all periods presented. (2) Certain Plains entities have issued promissory notes by and among such entities to facilitate financing. 'Proceeds from the issuance of related party notes' has an equal and offsetting cash outflow associated with our investment in related party notes, which is included as a component of 'Net cash used in investing activities.' (3) The six months ended June 30, 2025 includes a net cash outflow of $681 million for bolt-on acquisitions. (4) Cash distributions paid during the period presented. (5) Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow and Adjusted Free Cash Flow after Distributions to assess the amount of cash that is available for distributions, debt repayments, common equity repurchases and other general partnership purposes. Adjusted Free Cash Flow after Distributions shortages, if any, may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program. (6) Cash distributions paid to preferred and common unitholders during the period. (7) Excess Adjusted Free Cash Flow after Distributions is retained to establish reserves for future distributions, capital expenditures, debt reduction and other partnership purposes. Adjusted Free Cash Flow after Distributions shortages may be funded from previously established reserves, cash on hand or from borrowings under our credit facilities or commercial paper program. (8) See the 'Condensed Consolidated Cash Flow Data' table. (9) Management uses the non-GAAP financial liquidity measures Adjusted Free Cash Flow (Excluding Changes in Assets & Liabilities) and Adjusted Free Cash Flow after Distributions (Excluding Changes in Assets & Liabilities) to assess the underlying business liquidity and cash flow generating capacity excluding fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SELECTED ITEMS IMPACTING COMPARABILITY(in millions) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Selected Items Impacting Comparability: (1) (2) Derivative activities and inventory valuation adjustments (3) $ (8 ) $ (24 ) $ 27 $ (184 ) Long-term inventory costing adjustments (4) (19 ) (10 ) (17 ) 24 Deficiencies under minimum volume commitments, net (5) 9 (7 ) 16 5 Equity-indexed compensation expense (6) (8 ) (10 ) (18 ) (19 ) Foreign currency revaluation (7) (9 ) 7 (9 ) 17 Transaction-related expenses (8) (3 ) — (8 ) — Selected items impacting comparability - Adjusted EBITDA $ (38 ) $ (44 ) $ (9 ) $ (157 ) Gain on investments in unconsolidated entities, net — — 31 — Losses on asset sales, net (55 ) (1 ) (42 ) (1 ) Tax effect on selected items impacting comparability (9 ) 8 (12 ) 37 Aggregate selected items impacting noncontrolling interests — (1 ) (2 ) (6 ) Selected items impacting comparability - Adjusted net income attributable to PAA $ (102 ) $ (38 ) $ (34 ) $ (127 )___________________________________ (1) Certain of our non-GAAP financial measures may not be impacted by each of the selected items impacting comparability. See the 'Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation' and 'Computation of Basic and Diluted Adjusted Net Income Per Common Unit' tables for additional details on how these selected items impacting comparability affect such measures. (2) Includes results from continuing operations and discontinued operations for all periods presented. (3) We use derivative instruments for risk management purposes and our related processes include specific identification of hedging instruments to an underlying hedged transaction. Although we identify an underlying transaction for each derivative instrument we enter into, there may not be an accounting hedge relationship between the instrument and the underlying transaction. In the course of evaluating our results, we identify differences in the timing of earnings from the derivative instruments and the underlying transactions and exclude the related gains and losses in determining adjusted results such that the earnings from the derivative instruments and the underlying transactions impact adjusted results in the same period. In addition, we exclude gains and losses on derivatives that are related to (i) investing activities, such as the purchase of linefill, and (ii) purchases of long-term inventory. We also exclude the impact of corresponding inventory valuation adjustments, as applicable. For applicable periods, we excluded gains and losses from the mark-to-market of the embedded derivative associated with the Preferred Distribution Rate Reset Option of our Series A preferred units. (4) We carry crude oil and NGL inventory that is comprised of minimum working inventory requirements in third-party assets and other working inventory that is needed for our commercial operations. We consider this inventory necessary to conduct our operations and we intend to carry this inventory for the foreseeable future. Therefore, we classify this inventory as long-term on our balance sheet and do not hedge the inventory with derivative instruments (similar to linefill in our own assets). We treat the impact of changes in the average cost of the long-term inventory (that result from fluctuations in market prices) and write-downs of such inventory that result from price declines as a selected item impacting comparability. (5) We, and certain of our equity method investees, have certain agreements that require counterparties to deliver, transport or throughput a minimum volume over an agreed upon period. Substantially all of such agreements were entered into with counterparties to economically support the return on capital expenditure necessary to construct the related asset. Some of these agreements include make-up rights if the minimum volume is not met. We record a receivable from the counterparty in the period that services are provided or when the transaction occurs, including amounts for deficiency obligations from counterparties associated with minimum volume commitments. If a counterparty has a make-up right associated with a deficiency, we defer the revenue attributable to the counterparty's make-up right and subsequently recognize the revenue at the earlier of when the deficiency volume is delivered or shipped, when the make-up right expires or when it is determined that the counterparty's ability to utilize the make-up right is remote. We include the impact of amounts billed to counterparties for their deficiency obligation, net of applicable amounts subsequently recognized into revenue or equity earnings, as a selected item impacting comparability. We believe the inclusion of the contractually committed revenues associated with that period is meaningful to investors as the related asset has been constructed, is standing ready to provide the committed service and the fixed operating costs are included in the current period results. (6) Our total equity-indexed compensation expense includes expense associated with awards that will be settled in units and awards that will be settled in cash. The awards that will be settled in units are included in our diluted net income per unit calculation when the applicable performance criteria have been met. We consider the compensation expense associated with these awards as a selected item impacting comparability as the dilutive impact of the outstanding awards is included in our diluted net income per unit calculation, as applicable. The portion of compensation expense associated with awards that will be settled in cash is not considered a selected item impacting comparability. (7) During the periods presented, there were fluctuations in the value of the Canadian dollar to the U.S. dollar, resulting in the realization of foreign exchange gains and losses on the settlement of foreign currency transactions as well as the revaluation of monetary assets and liabilities denominated in a foreign currency. The associated gains and losses are not integral to our results and were thus classified as a selected item impacting comparability. (8) Primarily related to acquisitions completed during the first half of 2025. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY CRUDE OIL(in millions) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Revenues (1) $ 10,622 $ 12,735 $ 22,061 $ 24,317 Purchases and related costs (1) (9,742 ) (11,820 ) (20,231 ) (22,484 ) Field operating costs (2) (279 ) (272 ) (571 ) (538 ) Segment general and administrative expenses (2) (3) (75 ) (72 ) (155 ) (146 ) Equity earnings in unconsolidated entities 94 106 196 201 Adjustments: (4) Depreciation and amortization of unconsolidated entities 20 17 40 37 Derivative activities and inventory valuation adjustments 52 (4 ) 28 34 Long-term inventory costing adjustments 17 4 18 (25 ) Deficiencies under minimum volume commitments, net (9 ) 7 (16 ) (5 ) Equity-indexed compensation expense 8 10 18 19 Foreign currency revaluation 9 (2 ) 9 (19 ) Transaction-related expenses 3 — 8 — Segment amounts attributable to noncontrolling interests (5) (140 ) (133 ) (265 ) (261 ) Crude Oil Segment Adjusted EBITDA / Adjusted EBITDA from Crude Oil $ 580 $ 576 $ 1,140 $ 1,130 Crude Oil maintenance capital expenditures $ 43 $ 41 $ 74 $ 87 ____________________________ (1) Includes intersegment amounts. (2) Field operating costs and Segment general and administrative expenses include equity-indexed compensation expense. (3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. (4) Represents adjustments utilized by our CODM in the evaluation of segment results. Many of these adjustments are also considered selected items impacting comparability when calculating consolidated non-GAAP financial measures such as Adjusted EBITDA. See the 'Selected Items Impacting Comparability' table for additional discussion. (5) Reflects amounts attributable to noncontrolling interests in the Permian JV, Cactus II Pipeline LLC and Red River Pipeline LLC. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SELECTED FINANCIAL DATA BY NGL(in millions) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Revenues (1) $ 26 $ 25 $ 67 $ 86 Purchases and related costs (1) (22 ) (21 ) (55 ) (66 ) Field operating costs (2) (7 ) (8 ) (14 ) (15 ) Segment general and administrative expenses (2) (3) (7 ) (7 ) (13 ) (14 ) NGL Segment Adjusted EBITDA (4) $ (10 ) $ (11 ) $ (15 ) $ (9 ) Adjusted EBITDA from NGL Discontinued Operations (5) 97 105 291 262 Adjusted EBITDA from NGL $ 87 $ 94 $ 276 $ 253 Maintenance capital expenditures from NGL continuing operations $ 1 $ 2 $ 3 $ 3 Maintenance capital expenditures from NGL discontinued operations 20 18 28 28 NGL maintenance capital expenditures $ 21 $ 20 $ 31 $ 31 _______________________________ (1) Includes intersegment amounts. (2) Field operating costs and segment general and administrative expenses include certain costs that are part of the overhead of continuing operations, including information technology, insurance and other shared services costs. (3) Segment general and administrative expenses reflect direct costs attributable to each segment and an allocation of other expenses to the segments. The proportional allocations by segment require judgment by management and are based on the business activities that exist during each period. (4) Includes results from continuing operations and excludes amounts related to discontinued operations for all periods presented. (5) See the 'Reconciliation of Adjusted EBITDA from NGL Discontinued Operations' table for a reconciliation to the most directly comparable measure as reported in accordance with GAAP. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) DISCONTINUED OPERATIONS DETAIL(in millions) Components of Income from Discontinued Operations, Net of Tax: Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Revenues $ 211 $ 176 $ 745 $ 532 Cost and Expenses: Purchases and related costs 10 20 252 232 Field operating costs 53 70 122 155 General and administrative expenses 12 14 26 29 Depreciation and amortization 27 31 57 62 (Gains)/losses on asset sales, net 13 (1 ) 13 (2 ) Total costs and expenses 115 134 470 476 Income from discontinued operations before tax 96 42 275 56 Current income tax expense (14 ) (17 ) (54 ) (55 ) Deferred income tax (expense)/benefit (12 ) 7 (15 ) 41 Income from discontinued operations, net of tax $ 70 $ 32 $ 206 $ 42 Reconciliation of Adjusted EBITDA from NGL Discontinued Operations: Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Income from discontinued operations, net of tax $ 70 $ 32 $ 206 $ 42 Income tax expense from discontinued operations 26 10 69 14 Depreciation and amortization from discontinued operations 27 31 57 62 (Gains)/losses on asset sales, net from discontinued operations 13 (1 ) 13 (2 ) Adjustments attributable to discontinued operations (1): Derivative activities and inventory valuation adjustments (44 ) 28 (55 ) 150 Long-term inventory costing adjustments 2 6 (1 ) 1 Foreign currency revaluation 3 (1 ) 2 (5 ) Adjusted EBITDA from NGL Discontinued Operations $ 97 $ 105 $ 291 $ 262 _____________________________ (1) See the 'Selected Items Impacting Comparability' table for additional information. Investment Capital from NGL Discontinued Operations: Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 NGL investment capital expenditures from discontinued operations $ 27 $ 23 $ 68 $ 37PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) OPERATING DATA (1) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Crude Oil Volumes Crude oil pipeline tariff (by region) Permian Basin (2) 7,223 6,701 7,047 6,565 South Texas / Eagle Ford (2) 542 395 517 386 Mid-Continent (2) 537 530 477 508 Gulf Coast (2) 219 223 216 213 Rocky Mountain (2) 508 495 501 497 Western 289 245 268 252 Canada 341 349 348 348 Total crude oil pipeline tariff (2) 9,659 8,938 9,374 8,769 NGL Volumes (3) NGL fractionation 151 129 154 128 NGL pipeline tariff 225 221 230 217 Propane and butane sales 54 54 100 91______________________________ (1) Average volumes in thousands of barrels per day calculated as the total volumes (attributable to our interest for assets owned by unconsolidated entities or through undivided joint interests) for the period divided by the number of days in the period. Volumes associated with assets acquired during the period represent total volumes for the number of days we actually owned the assets divided by the number of days in the period. (2) Includes volumes (attributable to our interest) from assets owned by unconsolidated entities. (3) Includes volumes from assets associated with continuing operations and discontinued operations. PLAINS ALL AMERICAN PIPELINE, L.P. AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) SUPPLEMENTAL NON-GAAP RECONCILIATIONS(in millions) Supplemental Adjusted EBITDA attributable to PAA Reconciliation: Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Crude Oil Segment Adjusted EBITDA $ 580 $ 576 $ 1,140 $ 1,130 NGL Segment Adjusted EBITDA (10 ) (11 ) (15 ) (9 ) Adjusted EBITDA from NGL Discontinued Operations (1) 97 105 291 262 Adjusted other income, net (2) 5 4 10 8 Adjusted EBITDA attributable to PAA (3) $ 672 $ 674 $ 1,426 $ 1,391 _____________________________ (1) See the 'Reconciliation of Adjusted EBITDA from NGL Discontinued Operations Reconciliation' table for a reconciliation to the most directly comparable measure as reported in accordance with GAAP. (2) Represents 'Other income, net' as reported on our Condensed Consolidated Statements of Operations, excluding interest income on promissory notes by and among certain Plains entities, as well as other income, net attributable to noncontrolling interests, adjusted for selected items impacting comparability. See the 'Selected Items Impacting Comparability' table for additional information. (3) See the 'Net Income to Adjusted EBITDA attributable to PAA and Implied DCF Reconciliation' table for reconciliation to Net Income. PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS(in millions, except per share data) Three Months EndedJune 30, 2025 Three Months EndedJune 30, 2024 Consolidating Consolidating PAA Adjustments (1) PAGP PAA Adjustments (1) PAGP REVENUES $ 10,642 $ — $ 10,642 $ 12,757 $ — $ 12,757 COSTS AND EXPENSES Purchases and related costs 9,758 — 9,758 11,838 — 11,838 Field operating costs 286 — 286 280 — 280 General and administrative expenses 82 2 84 79 2 81 Depreciation and amortization 235 — 235 226 — 226 Losses on asset sales, net 42 — 42 2 — 2 Total costs and expenses 10,403 2 10,405 12,425 2 12,427 OPERATING INCOME 239 (2 ) 237 332 (2 ) 330 OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 94 — 94 106 — 106 Interest expense, net (133 ) 23 (110 ) (111 ) 15 (96 ) Other income, net 31 (23 ) 8 23 (15 ) 8 INCOME FROM CONTINUING OPERATIONS BEFORE TAX 231 (2 ) 229 350 (2 ) 348 Current income tax expense from continuing operations (1 ) — (1 ) (52 ) — (52 ) Deferred income tax expense from continuing operations (3 ) (12 ) (15 ) — (12 ) (12 ) INCOME FROM CONTINUING OPERATIONS, NET OF TAX 227 (14 ) 213 298 (14 ) 284 INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX 70 — 70 32 — 32 NET INCOME 297 (14 ) 283 330 (14 ) 316 Net income attributable to noncontrolling interests (87 ) (166 ) (253 ) (80 ) (197 ) (277 ) NET INCOME ATTRIBUTABLE TO PAGP $ 210 $ (180 ) $ 30 $ 250 $ (211 ) $ 39 Basic net income per Class A share (2): Continuing operations $ 0.05 $ 0.15 Discontinued operations $ 0.10 $ 0.05 Basic net income per Class A share $ 0.15 $ 0.20 Diluted net income per Class A share (2): Continuing operations $ 0.05 $ 0.15 Discontinued operations $ 0.10 $ 0.04 Diluted net income per Class A share $ 0.15 $ 0.19 _________________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) See the 'Computation of Basic and Diluted Net Income Per Class A Share' table for additional information. PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS(in millions, except per share data) Six Months EndedJune 30, 2025 Six Months EndedJune 30, 2024 Consolidating Consolidating PAA Adjustments (1) PAGP PAA Adjustments (1) PAGP REVENUES $ 22,119 $ — $ 22,119 $ 24,396 $ — $ 24,396 COSTS AND EXPENSES Purchases and related costs 20,277 — 20,277 22,543 — 22,543 Field operating costs 585 — 585 553 — 553 General and administrative expenses 168 3 171 160 3 163 Depreciation and amortization 466 — 466 449 — 449 Losses on asset sales, net 29 — 29 3 — 3 Total costs and expenses 21,525 3 21,528 23,708 3 23,711 OPERATING INCOME 594 (3 ) 591 688 (3 ) 685 OTHER INCOME/(EXPENSE) Equity earnings in unconsolidated entities 196 — 196 201 — 201 Gain on investments in unconsolidated entities, net 31 — 31 — — — Interest expense, net (260 ) 43 (217 ) (205 ) 15 (190 ) Other income, net 57 (43 ) 14 18 (15 ) 3 INCOME FROM CONTINUING OPERATIONS BEFORE TAX 618 (3 ) 615 702 (3 ) 699 Current income tax expense from continuing operations (6 ) — (6 ) (68 ) — (68 ) Deferred income tax (expense)/benefit from continuing operations (5 ) (35 ) (40 ) 5 (25 ) (20 ) INCOME FROM CONTINUING OPERATIONS, NET OF TAX 607 (38 ) 569 639 (28 ) 611 INCOME FROM DISCONTINUED OPERATIONS, NET OF TAX 206 — 206 42 — 42 NET INCOME 813 (38 ) 775 681 (28 ) 653 Net income attributable to noncontrolling interests (160 ) (501 ) (661 ) (166 ) (406 ) (572 ) NET INCOME ATTRIBUTABLE TO PAGP $ 653 $ (539 ) $ 114 $ 515 $ (434 ) $ 81 Basic net income per Class A share (2): Continuing operations $ 0.29 $ 0.35 Discontinued operations $ 0.29 $ 0.06 Basic net income per Class A share $ 0.58 $ 0.41 Diluted net income per Class A share (2): Continuing operations $ 0.29 $ 0.35 Discontinued operations $ 0.28 $ 0.06 Diluted net income per Class A share $ 0.57 $ 0.41 _________________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) See the 'Computation of Basic and Diluted Net Income Per Class A Share' table for additional information. PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) CONDENSED CONSOLIDATING BALANCE SHEET DATA(in millions) June 30, 2025 December 31, 2024 Consolidating Consolidating PAA Adjustments (1) PAGP PAA Adjustments (1) PAGP ASSETS Current assets (2) $ 4,688 $ (30 ) $ 4,658 $ 4,802 $ (26 ) $ 4,776 Property and equipment, net 14,177 — 14,177 13,446 — 13,446 Investments in unconsolidated entities 2,709 — 2,709 2,811 — 2,811 Intangible assets, net 1,636 — 1,636 1,677 — 1,677 Deferred tax asset — 1,175 1,175 — 1,220 1,220 Linefill 940 — 940 904 — 904 Long-term operating lease right-of-use assets, net 182 — 182 189 — 189 Long-term inventory 234 — 234 242 — 242 Long-term assets of discontinued operations 2,482 — 2,482 2,349 — 2,349 Other long-term assets, net 107 — 107 142 — 142 Total assets $ 27,155 $ 1,145 $ 28,300 $ 26,562 $ 1,194 $ 27,756 LIABILITIES AND PARTNERS' CAPITAL Current liabilities (3) $ 4,679 $ (31 ) $ 4,648 $ 4,950 $ (26 ) $ 4,924 Senior notes, net 8,133 — 8,133 7,141 — 7,141 Other long-term debt, net 71 — 71 70 — 70 Long-term operating lease liabilities 190 — 190 192 — 192 Long-term liabilities of discontinued operations 598 — 598 576 — 576 Other long-term liabilities and deferred credits 535 — 535 537 — 537 Total liabilities 14,206 (31 ) 14,175 13,466 (26 ) 13,440 Partners' capital excluding noncontrolling interests 9,706 (8,352 ) 1,354 9,813 (8,462 ) 1,351 Noncontrolling interests 3,243 9,528 12,771 3,283 9,682 12,965 Total partners' capital 12,949 1,176 14,125 13,096 1,220 14,316 Total liabilities and partners' capital $ 27,155 $ 1,145 $ 28,300 $ 26,562 $ 1,194 $ 27,756_______________________________ (1) Represents the aggregate consolidating adjustments necessary to produce consolidated financial statements for PAGP. (2) Includes current assets of discontinued operations of $385 million and $415 million as of June 30, 2025 and December 31, 2024, respectively. (3) Includes current liabilities of discontinued operations of $313 million and $350 million as of June 30, 2025 and December 31, 2024, respectively. PLAINS GP HOLDINGS AND SUBSIDIARIESFINANCIAL SUMMARY (unaudited) COMPUTATION OF BASIC AND DILUTED NET INCOME PER CLASS A SHARE(in millions, except per share data) Three Months EndedJune 30, Six Months EndedJune 30, 2025 2024 2025 2024 Basic Net Income per Class A Share Net income attributable to PAGP from continuing operations $ 10 $ 30 $ 56 $ 69 Net income attributable to PAGP from discontinued operations $ 20 $ 9 $ 58 $ 12 Basic weighted average Class A shares outstanding 198 197 198 197 Basic Net Income per Class A Share: Continuing operations $ 0.05 $ 0.15 $ 0.29 $ 0.35 Discontinued operations $ 0.10 $ 0.05 $ 0.29 $ 0.06 Basic net income per Class A share $ 0.15 $ 0.20 $ 0.58 $ 0.41 Diluted Net Income per Class A Share Net income attributable to PAGP from continuing operations $ 10 $ 30 $ 56 $ 69 Net income attributable to PAGP from discontinued operations $ 20 $ 9 $ 58 $ 12 Incremental net income attributable to PAGP resulting from assumed exchange of AAP Management Units — 1 8 — Net income attributable to PAGP from discontinued operations including incremental net income from assumed exchange of AAP Management Units $ 20 $ 10 $ 66 $ 12 Basic weighted average Class A shares outstanding 198 197 198 197 Dilutive shares resulting from assumed exchange of AAP Management Units — 35 35 — Diluted weighted average Class A shares outstanding 198 232 233 197 Diluted Net Income per Class A Share: Continuing operations $ 0.05 $ 0.15 $ 0.29 $ 0.35 Discontinued operations $ 0.10 $ 0.04 $ 0.28 $ 0.06 Diluted net income per Class A share $ 0.15 $ 0.19 $ 0.57 $ 0.41 Except for the historical information contained herein, the matters discussed in this release consist of forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in the forward-looking statements. These risks and uncertainties include, among other things, the following: general economic, market or business conditions in the United States and elsewhere (including the potential for a recession or significant slowdown in economic activity levels, the risk of persistently high inflation and supply chain issues, the impact of global public health events, such as pandemics, on demand and growth, and the timing, pace and extent of economic recovery) that impact (i) demand for crude oil, drilling and production activities and therefore the demand for the midstream services we provide and (ii) commercial opportunities available to us; declines in global crude oil demand and/or crude oil prices or other factors that correspondingly lead to a significant reduction of North American crude oil and NGL production (whether due to reduced producer cash flow to fund drilling activities or the inability of producers to access capital, or both, the unavailability of pipeline and/or storage capacity, the shutting-in of production by producers, government-mandated pro-ration orders, or other factors), which in turn could result in significant declines in the actual or expected volume of crude oil and NGL shipped, processed, purchased, stored, fractionated and/or gathered at or through the use of our assets and/or the reduction of the margins we can earn or the commercial opportunities that might otherwise be available to us; fluctuations in refinery capacity and other factors affecting demand for various grades of crude oil and NGL and resulting changes in pricing conditions or transportation throughput requirements; unanticipated changes in crude oil and NGL market structure, grade differentials and volatility (or lack thereof); the effects of competition and capacity overbuild in areas where we operate, including downward pressure on rates, volumes and margins, contract renewal risk and the risk of loss of business to other midstream operators who are willing or under pressure to aggressively reduce transportation rates in order to capture or preserve customers; the availability of, and our ability to consummate, acquisitions, divestitures (including the pending divestiture of our Canadian NGL Business), joint ventures or other strategic opportunities and realize benefits therefrom; the successful operation of joint ventures and joint operating arrangements we enter into from time to time, whether relating to assets operated by us or by third parties, and the successful integration and future performance of acquired assets or businesses; environmental liabilities, litigation or other events that are not covered by an indemnity, insurance or existing reserves; negative societal sentiment regarding the hydrocarbon energy industry and the continued development and consumption of hydrocarbons, which could influence consumer preferences and governmental or regulatory actions that adversely impact our business; the occurrence of a natural disaster, catastrophe, terrorist attack (including eco-terrorist attacks) or other event that materially impacts our operations, including cyber or other attacks on our or our service providers' electronic and computer systems; weather interference with business operations or project construction, including the impact of extreme weather events or conditions (including hurricanes, floods, wildfires and drought); the impact of current and future laws, rulings, legislation, governmental regulations, executive orders, trade policies, trade tariffs, accounting standards and statements, and related interpretations that (i) prohibit, restrict or regulate the development of oil and gas resources and the related infrastructure on lands dedicated to or served by our pipelines or (ii) negatively impact our ability to develop, operate or repair midstream assets, or (iii) otherwise negatively impact our business or increase our exposure to risk; negative impacts on production levels in the Permian Basin or elsewhere due to issues associated with (or laws, rules or regulations relating to) hydraulic fracturing and related activities (including wastewater injection or disposal), including earthquakes, subsidence, expansion or other issues; the pace of development of natural gas or other infrastructure and its impact on expected crude oil production growth in the Permian Basin; the refusal or inability of our customers or counterparties to perform their obligations under their contracts with us (including commercial contracts, asset sale agreements and other agreements), whether justified or not and whether due to financial constraints (such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors; loss of key personnel and inability to attract and retain new talent; disruptions to futures markets for crude oil, NGL and other petroleum products, which may impair our ability to execute our commercial or hedging strategies; the effectiveness of our risk management activities; shortages or cost increases of supplies, materials or labor; maintenance of our credit ratings and ability to receive open credit from our suppliers and trade counterparties; our inability to perform our obligations under our contracts, whether due to non-performance by third parties, including our customers or counterparties, market constraints, third-party constraints, supply chain issues, legal constraints (including governmental orders or guidance), or other factors or events; the incurrence of costs and expenses related to unexpected or unplanned capital or maintenance expenditures, third-party claims or other factors; failure to implement or capitalize, or delays in implementing or capitalizing, on investment capital projects, whether due to permitting delays, permitting withdrawals or other factors; tightened capital markets or other factors that increase our cost of capital or limit our ability to obtain debt or equity financing on satisfactory terms to fund additional acquisitions, investment capital projects, working capital requirements and the repayment or refinancing of indebtedness; the amplification of other risks caused by volatile or closed financial markets, capital constraints, liquidity concerns and inflation; the use or availability of third-party assets upon which our operations depend and over which we have little or no control; the currency exchange rate of the Canadian dollar to the United States dollar; the deferral of current revenue recognition attributable to deficiency payments received from customers who fail to ship or move their minimum contracted volumes; significant under-utilization of our assets and facilities; increased costs, or lack of availability, of insurance; fluctuations in the debt and equity markets, including the price of our units at the time of vesting under our long-term incentive plans; risks related to the development and operation of our assets; and other factors and uncertainties inherent in the transportation, storage, terminalling and marketing of crude oil, as well as in the processing, transportation, fractionation, storage and marketing of NGL as discussed in the Partnerships' filings with the Securities and Exchange Commission. About Plains:PAA is a publicly traded master limited partnership that owns and operates midstream energy infrastructure and provides logistics services for crude oil and natural gas liquids ('NGL'). PAA owns an extensive network of pipeline gathering and transportation systems, in addition to terminalling, storage, processing, fractionation and other infrastructure assets serving key producing basins, transportation corridors and major market hubs and export outlets in the United States and Canada. On average, PAA handles over 9 million barrels per day of crude oil and NGL. PAGP is a publicly traded entity that owns an indirect, non-economic controlling general partner interest in PAA and an indirect limited partner interest in PAA, one of the largest energy infrastructure and logistics companies in North America. PAA and PAGP are headquartered in Houston, Texas. For more information, please visit Contacts: Blake Fernandez Vice President, Investor Relations (866) 809-1291 Michael Gladstein Director, Investor Relations (866) 809-1291
Globe and Mail
19-06-2025
- Business
- Globe and Mail
Why Plains All American Pipeline Stock Was a Winner on Wednesday
Plains All American Pipeline (NASDAQ: PAA) stock was the pipeline to increased gains for investors on Wednesday. They traded the shares up by nearly 4% on news of an important divestment, and that rate easily beat the essentially flat-lining S&P 500 index. Selling the Canadian NGL business After market close on Tuesday, Plains and its majority owner, Plains GP Holdings (NASDAQ: PAGP), disclosed that they had finalized agreements to sell "substantially all" of their natural gas liquids (NGL) business. The acquirer is a Canadian peer company, Keyera, and the deal is to be effected in cash. The price is roughly 5.15 billion Canadian dollars ($3.79 billion). The sale is expected to close in the first quarter of 2026, subject to the applicable regulatory approvals and closing conditions. Plains added that, accounting for a potential one-time "special distribution" estimated at $0.35 per unit to both Plains common unit holders and Plains GP shareholders, it will reap total proceeds of around $3 billion from the divestment. The special distribution payment is subject to approval by Plains's board of directors. Following the sale, Keyera will own Plains' Canadian NGL assets, but Plains will retain those in its native U.S. The latter company's crude oil assets in Canada are not part of the deal. A win-win, says the seller In its press release on the deal, Plains quoted CEO Willie Chiang as saying that it's "a win-win transaction for both Plains and Keyera. Plains is exiting the Canadian NGL business at an attractive valuation while Keyera is receiving highly complementary and critical infrastructure in a strategic market." Judging by their collective reaction, Plains investors agree with this assessment. It will provide the company with gobs of capital while slimming its operational structure and allowing it to concentrate more on the crude oil segment. Should you invest $1,000 in Plains All American Pipeline right now? Before you buy stock in Plains All American Pipeline, consider this: The Motley Fool Stock Advisor analyst team just identified what they believe are the 10 best stocks for investors to buy now… and Plains All American Pipeline wasn't one of them. The 10 stocks that made the cut could produce monster returns in the coming years. Consider when Netflix made this list on December 17, 2004... if you invested $1,000 at the time of our recommendation, you'd have $658,297!* Or when Nvidia made this list on April 15, 2005... if you invested $1,000 at the time of our recommendation, you'd have $883,386!* Now, it's worth noting Stock Advisor 's total average return is992% — a market-crushing outperformance compared to172%for the S&P 500. Don't miss out on the latest top 10 list, available when you join Stock Advisor. See the 10 stocks » *Stock Advisor returns as of June 9, 2025
Yahoo
18-06-2025
- Business
- Yahoo
Keyera to acquire Plains' Canadian natural gas liquids business for $3.77bn
Keyera has entered into a definitive agreement to purchase the Canadian natural gas liquids (NGL) business of Plains All American Pipeline and Plains GP for C$5.15bn ($3.77bn) in cash. This acquisition is set to expand Keyera's presence in the NGL market by creating a NGL corridor from Western to Eastern Canada by placing all assets under Canadian ownership. Furthermore, the combined platform provides access to high-demand markets via liquefied petroleum gas export facilities on the west coast, while also connecting to significant consumption centres in Eastern Canada and the US. The assets involved in the transaction encompass NGL fractionation, storage, and rail and truck terminals across Alberta, Saskatchewan, Manitoba and Ontario. The transaction is anticipated to close in the first half of 2026, subject to customary closing conditions including regulatory approvals. Keyera president and CEO Dean Setoguchi said: 'This is a highly strategic acquisition that strengthens our core business and accelerates our growth trajectory. The assets we are acquiring are high-quality, synergistic, and strongly aligned with our operational footprint and expertise. 'This transaction enhances our ability to serve customers, capture meaningful operational efficiencies, and deliver sustainable long-term value for shareholders, while also helping to reinforce Canada's position as a global energy leader.' While Plains will divest its Canadian NGL business, it will retain a substantial portion of its assets in the US, as well as all of its crude oil assets in Canada, as part of the transaction. The company will utilise the proceeds from the transaction to undertake disciplined bolt-on mergers and acquisitions to enhance and broaden the crude oil-focused portfolio and optimise its capital structure. The restructuring and sale of the remaining Canadian crude assets are projected to result in entity-level tax payable in Canada of approximately $360m. Plains chairman and CEO Willie Chiang said: 'Today's announcement is a win-win transaction for both Plains and Keyera. Plains is exiting the Canadian NGL business at an attractive valuation while Keyera is receiving highly complementary and critical infrastructure in a strategic market. 'Successful completion of this transformative transaction advances our efficient growth strategy and establishes Plains as the premier pure play crude oil midstream entity with highly strategic assets linking North American supply to key demand centres.' "Keyera to acquire Plains' Canadian natural gas liquids business for $3.77bn" was originally created and published by Offshore Technology, a GlobalData owned brand. The information on this site has been included in good faith for general informational purposes only. It is not intended to amount to advice on which you should rely, and we give no representation, warranty or guarantee, whether express or implied as to its accuracy or completeness. You must obtain professional or specialist advice before taking, or refraining from, any action on the basis of the content on our site. Sign in to access your portfolio
