Good day and thank you for standing by. Welcome to the 2024 Second Quarter Plains All American Pipeline Earnings Call. At this time, all participants are on listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. I’d like to hand the conference over to your first speaker today, Blake Fernandez, VP of Investment Relations. Please go ahead.

Thank you, Marvin. Good morning. And welcome to Plains All American second quarter 2024 earnings call. Today’s slide presentation is posted on the Investor Relations website under the News and Events section at plains.com. An audio replay will also be available following today’s call. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on Slide 2. An overview of today’s call is provided on Slide 3. A condensed consolidating balance sheet for PAGP and other reference materials are in the appendix. Today’s call will be hosted by our Chairman and CEO, Willie Chiang; Executive Vice President and CFO, Al Swanson; and other members of our management team. With that, I will now turn the call over to Willie.

Thank you, Blake. Good morning, everyone, and thank you for joining us. Today, we reported second quarter adjusted EBITDA attributable to PAA of $674 million. This exceeded our expectation, and it highlights our focus on execution and the ability of our team and asset base to respond to the ever-changing market dynamics. As a result of our year-to-date performance, bolt-on M&A contributions, and momentum as we enter the second half of the year, we’re raising the midpoint of our full year 2024 adjusted EBITDA guidance by $75 million to a new range of 2.725 billion to $2.775 billion. Our 2024 production outlook remains unchanged at an increase of 200,000 barrels a day to 300,000 barrels a day able to exit with the back half weighing. I would also note that while rigs are trending slightly below our initial expectations, efficiencies have largely offset the impact of a lower overall rig count. A high-level overview of our second quarter results and updated 2024 guidance is shown on Slides 3 and Slide 4. Consistent with our efficient growth strategy, Plains facilitated and acquired an additional 0.7% interest in the Wink-to-Webster Pipeline Company from Rattler Midstream for an aggregate cash consideration of approximately $20 million. Now, while this transaction is small, it’s a great example of how our numerous joint ventures, partnerships and joint ownership agreements provide us with a robust opportunity set as far as potential bolt-on transactions. Slide 5 provides an overview of our bolt-on activity since the second half of 2022. During this time, we’ve completed eight bolt-on acquisitions for an aggregate investment of approximately $535 million net to Plains. These transactions all complement our existing asset base, include strong returns that meet our thresholds, create incremental efficient growth opportunities and enhance our financial profile. With that, I’ll turn the call over to Al.

Thanks, Willie. We reported second quarter adjusted EBITDA net to PAA of $674 million. This reflects the benefit of higher tariff volumes and several market-based opportunities in our Crude Oil segment. The NGL segment experienced favorable iso-to-normal butane spread along with higher frac spreads on our unhedged C3+ spec product sales. Across both of our Crude Oil and NGL segments, we benefited from lower than expected operating expenses. Some of this will reverse in the second half of the year, but we remain diligent in managing costs and running efficient operations. Slides 9 and 10 in today’s appendix contain locks that provide details on our second quarter performance. A summary of our updated 2024 guidance is on Slide 11. Shifting to capital allocation, as illustrated on Slide 6, for 2024, we expect to generate approximately $1.55 billion of adjusted free cash flow, excluding changes in assets and liabilities, and including $130 million of bolt-on acquisitions, with approximately $1.15 billion to be allocated to common and preferred distributions. We will also continue to self-fund our capital program with $375 million of growth capital and $250 million of maintenance capital net to PAA. Finally, in June, we issued $650 million of senior unsecured notes due in 2034 at a rate of 5.7%. We will use the note proceeds and cash to repay the $750 million note maturing in November. With that, I’ll turn the call back to Willie.

Thanks, Al. Today’s results reflect another quarter of strong execution and we remain confident in our ability to continue delivering on our goals and initiatives. We’re progressing our disciplined bolt-on strategy and our efficiency efforts are resulting in cost containment throughout the company. Over the coming years, we expect a more durable and resilient cash flow profile, underpinned by contract extensions in the Permian long-haul business, and a shift towards more stable fee-based cash flow in our NGL segment. Plains remains well-positioned as North American energy supply will continue to be critical to energy reliability, affordability and security for the foreseeable future. Our strong operational and equity performance continues to reaffirm our strategy of cash flow discipline, generating meaningful free cash flow and increasing return of capital to your unit holders while maintaining financial flexibility. We appreciate your continued interest and support in Plains and we look forward to providing further updates in our earnings conference in November. With that, I’ll turn the call over to Blake, who will lead us into Q&A.

Thank you, Willie. As we enter the Q&A session, please limit yourself to one question and one follow-up. For those with additional questions, please feel free to return to the Q&A. 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. Marvin, please open the call for questions.

Thank you. [Operator Instructions] Our first question comes from the line of Tristan Richardson of Scotiabank. Your line is now open.

Hey. Good morning, guys.

Good morning.

Maybe just a question, Willie, on the Crude segment, seeing the guide come up there. And you noted you’re seeing your producer customers are seeing greater efficiencies. Curious, I mean, is that efficiencies better than expected kind of the key source of the change in the outlook for the Crude segment? And then, I guess, we’ve heard from producers this earnings season that these efficiency gains appear pretty sustainable as you look into 2025. You’d be kind of curious sort of the driver of the 2024 move, A, and then, B, sort of how you see efficiency gains trending as you exit into and look to the beginning of 2025?

Hey, Tristan. This is Jeremy. The overall guidance change was part NGL, part Crude. Within the Crude segment, there are some opportunistic captures in Canada and the U.S. As far as production growth, it’s been in line with expectations. But the producer has been able to do less but more. We’ve maintained the 200,000 barrel a day to 300,000 barrel a day production growth guidance. A little bit of outperformance in the Midland, a little underperformance in the Delaware driven by infrastructure constraints and lower natural gas prices. But we see those deferral of completions into the beginning of next year. So, we think a healthier, efficient producer is good for our business long-term. Increasing recovery, lower cycle time, us chasing less connections, more efficient capital on their side than ours. So, I’d say it’s directionally positive. It’s not the sole source for the increase in guidance, but it’s a positive trend for us.

I appreciate it, Jeremy. And then maybe just the follow-up on the NGL segment. Presumably, as the business becomes more fee-based and mixed, especially next year. Curious how we should think about less variability in the NGL business longer-term, and then maybe sort of at a high level, sort of where a base level of earnings for the NGL segment is once we have become more fee-based.

Yeah. Tristan, this is Jeremy again. What I would say is, we’re not going to get forward guidance on the NGL segment, but we’ve entered into a 15-plus year contract, which has replaced roughly a third of our frac spread exposure. We’re investing $150 million to $200 million to replace that business with gathering, fractionation, storage, transportation. So it’s going to look just like an integrated NGL value chain, which we already have. This is bolting on and bolstering that piece. So we’ll move from roughly 60-40 frac spread exposed to less than 50-50. So I’d say longer-term, this is definitely a more predictable chain, but we do like this straddle business and we’ll continue to lean into that business as well.

Yeah. And Tristan, this is Willie, just to reinforce that point also. It’s -- historically, the market’s been very seasonal. It will always be seasonal. But what you see us doing by going to more fee-based starts to flatten that saddle out a little bit. I think there’ll always be seasonal opportunities. But everything we’re doing, as Jeremy pointed out, going to more fee-based, trying to flatten the saddle out, expanding our facilities over in Fort Saskatchewan, all play into that.

I appreciate it. Thank you guys very much.

Thanks, Tristan.

Thank you. One moment for our next question. Our next question comes from the line of Michael Blum of Wells Fargo. Your line is now open.

Thanks. Good morning, everyone. I wanted to ask on your, I believe it was your last call, you said that you expected the Crude segment EBITDA in 2026 to be roughly flat with 2024 EBITDA. Just wondering if that’s still a good Crude statement given the increase in 2024 EBITDA guidance here.

Yeah. Michael, this is Willie. I’ll take that one. Our perspective hasn’t changed. So, as you think about our performance this year versus 2026, same perspective. I just want to highlight, last time on the call, the reason we talked about that and gave not formal guidance, but a framework of kind of what we’re thinking was to make sure people understood that with these renegotiations of contracts, we don’t expect a cliff falling off in 2026. So short answer again is no change to the perspective on the Crude segment. We’re always working on a lot of things there to try to bolster our Crude business and more guidance will come as we outline 2025, 2026, as far as formal guidance coming out later.

Okay. Got it. Thanks for that. And then just to continue the discussion on Permian production growth, just wanted to get your perspective, just how you see things playing out over the balance of this year and next. And do you think over the next few years, you could see a scenario where Permian Crude takeaway could get tight again? Thanks.

Michael, this is Jeremy. In the near-term, like we said, there’s some infrastructure constraints, mostly in New Mexico, that being water, gas and lower gas prices just lend more completions in the Midland Basin. But we see that as pipelines come on, there’s another one announced yesterday, but as we get fourth quarter relief, you’re going to see the ability to add more production growth. So it’ll be a little lumpy as we hit infrastructure constraints, but we see a directionally continuing increase to the 200,000 barrels a day to 300,000 barrels a day a year that we’ve stayed with and naturally the Basin will get tighter. Forward differentials don’t reflect that for next year, but contracting discussions, or as we’ve just had and others are having, reflect that the industry’s looking to sell more away from Midland as time progresses. So I think that’s directionally positive for our business and everything’s happening in line with the discussions we had with our shippers in the contract that we just completed.

Thank you.

Thank you. One moment for our next question. Our next question comes from the line of Jeremy Tonet of JPMorgan Securities. Your line is now open.

Hi. Good morning.

Hey, Jeremy.

I just wanted to pick up, I guess, on M&A opportunity set more kind of little bolt-ons there. How much depth do you see to that opportunity set going forward here? Just trying to get a feeling for what you see there.

Yeah. Thanks for the question, Jeremy. We have -- you’ve heard us talk about efficient growth and bolt-ons, and quite frankly, it’s been a niche for us. And the reason we showed the slide in the deck is to show just the number that we’ve done. And if you think about our asset base, where it sits and the integrated nature of it, we’re really, I think, uniquely positioned to be able to capture synergies. So, a lot of these bolt-ons, they aren’t processes that come out, but it’s more in discussions with our partners to see how do we get to win-win solutions and we’ve demonstrated that we can do that, and these are pipe sized, but they certainly, when you add them up, make a meaningful difference and the returns are great on them. And we think it’s a great use of our free cash flow. So we’ll continue to try to advance and develop those. I think if you think about the environment and where capital is tight, different partners have different constraints and desires. It’s kind of a target-rich environment to be able to have discussions and the question is, how many of them can you bring to fruition and we’ll just continue to plug away on that. And then maybe just to take it one step further, if you were asking about broader M&A and opportunity sets, we’ve been pretty open on the views that we think there is going to be more consolidation across the industry, whether it be in upstream, midstream, downstream, just because capital is more expensive and you start growing a little bit more through efficiencies and synergies. And as we look at those, we’re just going to stay very disciplined, and if it makes sense to the unit holders to consider something like that, we would certainly be open. But in the meantime, I think there’s sufficient growth with bolt-ons. We have a deep opportunity set there and we’ll see what we can bring across the line.

Got it. That’s very helpful there. And then just maybe going a little bit further with Permian egress supply-demand, just wondering if you could provide a bit more color on customer conversations at this point. Do they see tightening and that kind of brings a different tone to the conversation or just kind of wondering how you think that stands right now?

I would say that we’ve had constructive dialogue. Obviously last quarter, we gave a significant update on our pipes. Those are large shippers that re-contracted with us and we’re certainly see where there’s available capacity, we’re having constructive dialogue. I don’t want to speak to specific pipes or interest. There’s a certain amount of exposure we want to retain because we see value and we need to clear the barrels our marketing affiliate buys. But with our third-party customers, we’re having very constructive dialogue, but we’re going to be patient.

Jeremy, this is Willie. A couple of other things on that. The last time we talked about the extension of our long-haul contracts and I think this really, our strategy there is really playing into what we think is going to happen. If you think about the last time the market was constrained, it was back in the 2014, 2015 range, 2016. And then there was a lot of capacity built and there was some markets were tight, spreads were wide, and we always expected at this point, you would start tightening the spare capacity. And I think the strategy on the long-haul extensions to 28, 29, 30 fit well, as well as retaining some open space on the ability to capture margins between Midland and the Gulf Coast is a strategy that we’ve laid out and I think it will pan out pretty well.

Got it. That’s helpful. Thank you.

Thank you.

Thank you. One moment for our next question. Our next question comes from a line of Manav Gupta of UBS. Your line is now open.

Congrats, guys. I just wanted to focus a little bit on the lower operating expenses, lower costs. You did mention it was part of the beat. So trying to understand what part of it is what can actually go on and benefit you in the second half of 2024 and 2025 as it relates to lowering overall expenses and cost.

Hey. Good morning, Manav. This is Chris Chandler. I will note that some of the lower costs in the first half were our ability to successfully defer some spend into the second half. So that won’t necessarily be sticky. But we’re, of course, always looking to optimize our operating cost. It certainly varies as volumes vary and utility prices vary, and we’ll look to optimize that going forward. But some of that was first half to second half deferrals.

Okay. And any quick commentary on possibility of redeeming the preferred in the future that could lower your cost of capital?

This is Al. No change in our thinking at this time. But as we have articulated, we do recognize that there may be a point in the future where we’ll reconsider that. So near-term now, medium- to longer-term, we will re-evaluate that.

Thank you, guys.

Thank you. One moment for next question. Our next question comes from line of Keith Stanley of Wolfe Research. Your line is now open.

Hi. Good morning. I think I clocked your prepared remarks at six minutes. That’s a new record for you guys. So congrats on that. I wanted to ask first on capital allocation. You’re having another really good year above expectations. In the past when that’s happened, I think you’ve been open about raising the distribution sooner or in larger size. Is that something that would be potentially on the table again or should we still assume $0.15 per unit Q4 as the target?

Yeah. Keith, this is Willie. Thanks for the question. I think we’ve been pretty steadfast in laying out our capital allocation strategies. And to answer your question directly, we’ve demonstrated and we will continue to focus on returns of capital to our unitholders. If we are able to have sustainable EBITDA going forward, we absolutely will consider that as we do our annual reviews on distribution. We’ve done $0.220 increases, we’ve stayed at the $0.15 and it’s an annual increase that we look at early every year. But to answer your question again, it’s absolutely part of our discussions. We want to get back more cash to the unitholders if we can.

Great. Thanks for that. Second, just tying back to the Permian, any early thoughts you would give on 2025 and the trajectory for volumes there, just given what you’re seeing with efficiencies, producer consolidation? I think Jeremy alluded to relief when Matterhorn comes on. Just any thoughts just directionally for next year?

Keith, this is Willie again. We not -- we haven’t given long-term guidance, but I’ll give you some general thoughts. We play for the long-term and our belief is that the Permian will be a key Basin for the world. Our growth of 200,000 barrel a day to 300,000 barrel a day, I think we’ve directionally said we expect that kind of to be more close to that than some of the incredible growth numbers that we’ve had in the past. There will be constraints. There will be lumpiness in the growth profile. But we are pretty bullish in the Permian and technology and some of the synergies that the E&P side is with the consolidations on being able to develop it more responsibly. So, more efficiently and -- more efficiently, not responsibly.

Thank you.

Thanks.

Thank you. One moment for our next question. Our next question comes from a line of Spiro Dounis of Citi. Your line is now open.

Thanks, Operator. Good morning, guys. I wanted to go back to Permian egress just quickly. So, certainly respect that you can’t say much for commercial reasons, but maybe if you could just give us a sense on maybe what’s open to contract here and help us sensitize how to think about the impact and as we think kind of out the 2026 plus, more pipeline capacity coming, what is your appetite to have kind of a more than 10% contract book open at that point?

Spiro, this is Jeremy. We haven’t provided that and don’t intend to, but I would say that there’s a small amount on Cactus I and Cactus II and then Basin has some uncontracted capacity. BridgeTex does have some as well, but we’re a 20% non-operated interest, so you might want to talk to one of them there. But Cactus I and II are largely contracted. We’ve retained some space to fill our dock and do some other things that we do and then there’s some space available to Cushing as well.

Got it. Okay. Thanks, Jeremy. Second one, maybe just quickly on the volume guidance. Notice that the Permian intra-Basin looks like that stepped up a bit. The gathering stepped down a bit, and so, sorry if I missed it. Maybe you just walk us through the dynamics there, what’s going on.

Sure. This is Jeremy again. It’s largely associated with transportation to Colorado City to hit other connecting carriers that have space. The pipelines towards Corpus are all full, so this is just getting additional barrels, production growth from the Basin out to Colorado City and hitting either the Houston or Mid-Continent markets. And some of that’s reflected in TMX. You see that if the heavy barrels leave the Mid-Continent, there’s some other barrels that have to take its place. So, we’ve seen some impact on Basin and some on, since Wink-to-Webster extended into Beaumont, you’re seeing more flows into Houston that can come across BridgeTex. So, it’s just as new pipeline dynamics and as production growth comes, it finds new markets.

Got it. Helpful as always. Thank you.

Thank you. One moment for our next question. Our next question comes from a line of Neel Mitra of Bank of America. Your line is now open.

Hi. thanks for taking my question. It looks like the 25 frac spread in Canada has, in 25 peaked up to close to $0.70 a gallon. Have you started looking at hedging that out and adding more stability on top of your fixed fee contracts that you talked about last quarter?

Hey. Neel, this is Jeremy. We have a continuous program of looking at hedging on a forward basis and current year and prop year, absolutely, we’re looking forward and we try to have a rolling program. So, we’re not going to provide guidance at this point, but we see market signals and we’re opportunistic around trading around those positions and putting hedges on as well. So, we continue to look at it. It’s not something we’re going to provide an update now, but we absolutely pay attention to the forward frac spread. It’s deeply backwarded, and so, opportunities are fewer and liquidity is fewer on a forward basis, but it’s definitely something we monitor and are active in.

And Neel, we typically give guidance closer to the beginning of the year, and as you probably know, the liquidity for the ability to hedge, as you move further out, it’s more difficult. So, more to come on that.

Okay. Perfect. And then, maybe back to Jeremy on this. We’ve talked about the Permian being back half-weighted with growth. Could you maybe talk about what you’ve seen in the second quarter with some of the negative Waha prices and if some of the heavier gas-cut wells have been shut in or we’ve seen delayed turn-in-line wells? And now that Matterhorn is delayed into early Q4, do you have any different expectations on if Q4 is heavier on growth versus Q3 or if your initial projections are unchanged?

So, Neel, I think we’re still in the range of 200,000 barrels a day to 300,000 barrels a day. We can move within that range. But we have seen growth to-date. So, it’s not like we didn’t see anything. Q4 was very strong last year, which flattened out for a period. But we continue to see growth. Weather has not been as hot this year as it has been. So, you’ve seen even growth during the summer where maybe you didn’t last year. Last year actually saw a decline in this period of time. So, directionally, it’s been positive and consistent. Maybe it’s delayed some completions in New Mexico and places that are more impacted. But that’s really just a quarter. So, that could be into the first quarter of next year. But Midland, like I said earlier, is outperformed. So, I would say it’s still in line with expectations. Timing of some completions has moved. But I think our forward guidance captures what our expectations are.

Okay. Perfect. Thank you so much.

Thank you. One moment for our next question. Our next question comes from line of AJ O'Donnell of TPH. Your line is now open.

Hey. Good morning. Thanks for taking my question. I just wanted to go back to some of the comments around the forward curves. You mentioned next year that those curves might not accurately be pricing in some of the conversations that you’re having. Just curious if you see gross differentials between Midland and Houston widening out beyond the average transport rate, and is that like more of a 2025 thing or is that later on in 2026?

Certainly not something we give forward guidance on. But if you look, MEH is something that doesn’t reflect on the water number. So, the prices to the water and the realized prices to the coast are $0.30 to $0.50 higher than that. So, you have to start from there. There’s the disconnect. And then from there, when you get into long-term contracting, you’re looking over a five-year period. So, the prompt doesn’t impact the total rate. It’s just a blended rate over time. So, I guess what I would say is, 2025 does show a lower number, but you have to get to the water and that premium is higher, both in Corpus and in Houston. And then it’s market driven, Corpus versus Houston versus Midland. So, it’s more nuanced than that. But near-term, the pipes are filling, and in 2026 plus, I think those are constructive dialogues between us and the customers.

Yeah. AJ, we have -- I think we’ve all experienced how forward curves are usually not good predictors of future prices. It’s just a methodology to be able to hedge and protect the future price. But as Jeremy said, when you start running out of spare capacity, the pricing signals change different behaviors. So, I would expect that as spare capacity tightens, we’ll start to see wider opportunities.

Okay. Thanks for that. Maybe just one last one on the NGL business. Just going back to some comments about wider spreads between iso and normal butane. I’m just curious about the opportunity there. Has that facility always been up and running? And if it hasn’t, I mean, going forward, will that be a quarter-to-quarter decision or how are you treating that?

Sure, AJ. We have multiple facilities. One runs all the time. One is more opportunistic. The spread flew out in Q2, wider than historical norm. We’ve got our outlook for the remainder of the year in it. But I’d say the biggest impact was in Q2, modest impact in Q3, and while we don’t forecast it in future periods, if it does, we’ll turn it on and we’ll operate. So, it’s just -- I would view that as more as opportunistic, and when it’s there, we’re capturing it.

Great. Thanks.

Thank you. One moment for our next question. Our next question comes from a line of Sunil Sibal of Seaport Global. Your line is now open.

Hi. Good morning, everybody, and thanks for all the color. So, it seems like, the kind of base operating assumptions for forward years are 200,000 barrels per day to 300,000 barrels per day of production growth in Permian, say, 3% to 4%. How should we think about that in the context of Plains Permian system so should we expect a similar kind of trajectory in volumes and cash flows from that system or there should be some expected changes? Seems like, there has been a little bit of realignment in terms of your competitors in the Basin. So, I just wanted to understand that a little bit.

I’d say that we’re a good proxy for the Basin’s overall growth. I think that’s a fair assessment.

Okay. Fair enough. And then one housekeeping for me seems like, your cash taxes are tracking fairly higher versus last year. Is there any timing issues there or how should we think about that for the remainder of 2024?

Yeah. They have been. Part of its income-based. Higher like this increase in guidance. Part of that is coming from our Canadian business. The taxes follow it. Also, in 2024, we repatriated a significant amount of money back and had a small withholding tax on that, and as well as just some refinements in our estimates as to depreciation and that. We would expect in 2025 to see taxes come back off of this higher level in 2025.

Okay. Thanks.

Thank you. One moment for our next question. Our next question comes from Neal Dingmann of Truist Securities. Your line is now open.

Good morning. Thanks for the time, guys. My first question is on M&A specifically. I’m just wondering, are there any packages currently in the market that would make strategic sense for you all, and given your available capacity out there, I’m just wondering, are you more inclined to continue to grow organically?

Neal, thank you for the question. Unfortunately, we can’t really talk about active processes or M&A. It’s something we talk about after it’s over, but I don’t think it changes our approach to be disciplined, and it’s got to be something where we can add significant value and compress multiple through synergies and our ability to operate. So, regardless of size, it’s got to be something that’s additive to our broader business and we can extract synergies and be more competitive than others, and if we can’t, we just won’t buy it.

Very helpful. And then just secondly on hedging, specifically given the strip that you’re seeing out there, do you plan to continue having the majority of the C3+ sales hedge going forward or is there a scenario where you could cause you to take a bit more exposure?

Neal, this is Jeremy. We do not leave a lot of it. But there’s a certain time of year when you sell NGLs and we’re towards the end of that. So we’ve got the vast majority of our barrels placed on firm contracts through this season, and the next year, when it comes up, beginning of the year, you’re selling for the next year. So, I think, what I would tell you is, incremental production, we have to sell, but we’re very rigorous in making sure that when it’s produced and when there’s the time to sell, we lock in our storage spreads, we lock in the downstream economics associated with it. We’re not sitting with a big basis exposure.

Sure. You’ve done a nice job with this. Thank you.

Thank you. One moment for our next question. Our next question comes from a line of John Mackay of Goldman. Your line is now open.

Hey, guys. Thanks for the time. I just wanted to look at the kind of second quarter Crude outperformance versus the implied guide for the back of the year. Just curious to kind of unpack a little more in terms of, maybe what you caught in the marketing this quarter or maybe from pipeline and loss allowances or the movement in OpEx versus kind of getting the benefit from some of these perming efficiencies, because we look at the back half of the year guidance that kind of implies flat on second quarter versus we’re talking about the fourth quarter step up here potentially. So just trying to unpack kind of that cadence? Thanks.

Sure. Sure. I think Al spoke and Chris spoke with some of the operating expenses, lower utilities in the second quarter for movements on pipe, so we have T&D. That doesn’t repeat in the second half, so that’s part of it. I’d say the other part of it is there’s some storage economics in the second quarter that we won’t see going forward. We had locked those in earlier in the year and taken those positions off in the second quarter. So I’d say it’s part trading and part operating expense, both pieces that not repeat. The rest of the outperformance should repeat.

I appreciate that. Just one last thing for me. We see the volume elsewhere in Crude outside the Permian kind of move around quarter-to-quarter. Know a lot of that is just kind of the accounting of volumes and something on the marketing side. But maybe if you could just give us a quick update on maybe just the run rate EBITDA generation off of that footprint and maybe how that should trend over the next couple of years, given that we’ve -- you’ve laid out a pretty clear story on the Permian side? Thanks.

Sure. What I would say is, we see outperformance in the Rockies, both rails from the Uinta that production growth continues and that goes into a couple of our facilities today and we expect that to continue so that’s been a good surprise. And then our Rockies pipes remain to be full. Our customers are happy along those pipes and we continue to see opportunities. So I’d say in Canada, gathering assets like Rainbow, the cross-border pipes and the Rockies integrated system that we have into Cushing, that’s been a source of outperformance plus the rails from the Uinta. The rest is performed in line with expectations.

All right. Appreciate the time. Thank you.

Thank you. One moment for next question. Our next question comes from the line of Theresa Chen of Barclays. Your line is now open.

Hi. Would you be able to quantify the iso-to-normal butane uplift in your results this quarter? And just thinking about the repeatability of this uplift, are you selling the iso domestically for England or just England alkylation feedstock in general or is this more related to getting your iso across the water for export, i.e. is it seasonal from driving demand or can you take advantage of the global shortage of octane agnostic of seasonality?

Sure, Teresa. I put it in the Q2, roughly $15 million range, and then Q3, probably the $5 million range roughly. And we find domestic shorts. We have a pretty big rail footprint in Canada and we’re able to hit any specific market. So we actually have unique access to specific markets that are short and so when it blows up, we optimize that. The same thing we do with our C3 sales and C4 sales from our straddle. We’re able to do the same thing with iso.

Theresa, this is Willie. As you think about the iso normal example that we just talked about. I don’t -- I wouldn’t characterize that as a structural change. You look at the large system we have, there’s always going to be opportunities -- market opportunities that we can capture. And I think what we’re seeing now is as infrastructure becomes a little tighter, some more of those are coming to fruition. We went through a period where it was very difficult to capture those markets because there’s lots of spare capacity and lots of infrastructure. So I would -- I understand your question, but I also wanted to reinforce that our system is big. It’s got a lot of optionality, and if there are opportunities out there, we’re able to capture them.

Understood. I meant more the structural demand for octane and iso as a feedstock for alkylation for that demand. So turning to the cost commentary of cost deferred into third quarter and maybe fourth quarter, any quantification or end points we should think about of how much that moved over?

Hi, Theresa. It’s Chris Chandler. No is the short answer, as in we won’t quantify the amount that is deferred versus sustainable cost savings. I would just reinforce our continued commitment to cost discipline and cost efficiency. And we’ll continue to look for opportunities to defer costs from the second half into the following years. And there’s a number of factors we take a look at, including expectations from customers, volumes on systems, weather, supplier availability, all the things you might imagine around optimizing our cost footprint. We’ll continue to do that.

Theresa, this is Blake. I would just add, obviously, we’ve contemplated that into our forward guidance.

Got it. Thank you very much.

Thanks, Theresa.

Thank you. I’m showing no further questions at this time. I’d now like to turn it back to Plains for closing remarks.

Well, listen, thanks for all of your questions. We look forward to seeing you soon on the road. Have a great day.

Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.