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 in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. Please be advised that today's conference is being recorded. I would like to hand the conference over to your first speaker today, Blake Fernandez, VP of Investor 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. 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 expectations and 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 to 300,000 barrels a day with an exit weighting in the back half. 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 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. 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 for 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 spreads 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 walks 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 and secured notes due in 2034 at a rate of 5.7%. We'll 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 the unitholders while maintaining financial flexibility. We appreciate your continued interest and support of 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 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. Marvin, please open the call for questions.

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

Hi, good morning, guys.

Good morning.

Maybe just a question, Willie. On the crude segment, seeing the guidance come up there and you noted your producer customers are seeing greater efficiencies. Curious if, 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. I'd be curious about the driver of the 2024 move A and then B, sort of how you see efficiency gains trending as you exit into 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 has been in line with expectations, but the producer has been able to do less with more. We've maintained the 200,000 to 300,000 barrels a day production growth guidance, a little bit of outperformance in the Midland and a little underperformance in the Delaware, driven by infrastructure constraints and lower natural gas prices. But we see those deferrals of completions into the beginning of next year. So we think a healthier, efficient producer is good for our business long-term. Increasing recoveries, lower cycle times, us chasing fewer connections, more efficient capital on their side and 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 in mix, especially next year, kind of curious how we should think about less variability in the NGL business longer term, and then maybe sort of at a high level where a base level of earnings for the NGL segment is once we become more fee-based?

Yes, Tristan, this is Jeremy again. What I would say is, we're not going to give forward guidance on the NGL segment, but we've entered into 15-plus year contracts, which have 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, and 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 exposure to less than 50/50. So I'd say longer term, this is definitely a more predictable chain, but we do like the straddle business, and we'll continue to lean into that business as well.

And, Tristan, this is Willie, just to reinforce that point. Historically, the market has 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 will 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 at Fort Saskatchewan, all play into that.

I appreciate it. Thank you guys very much.

Thanks, Tristan.

Thank you. One moment for the 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 want to ask on your, I believe in 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, true statement, given the increase in 2024 EBITDA guidance here.

Yes, 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 no, short answer again is no change in 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 continue the discussion on Permian production growth. Just want 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 the pipelines come on, there was another one announced yesterday, but as we get quarter-to-quarter relief you're going to see the ability to add more production growth. So it will be a little lumpy as we hit infrastructure constraints, but we see it directionally continuing to increase to the 200,000 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 are as we've just had and others are having reflect that the industry is looking to sell more away from Midland as time progresses. So I'd say that's directionally positive for our business and everything is happening in line with the discussions we had with our shippers and the contract that we just completed.

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

Hi, good morning.

Hi, Jeremy.

Hey. Just wanted to pick up, I guess, on the M&A opportunity set, more and 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.

Hi, Jeremy. Yes, thanks for the question. You've heard us talk about efficient growth and bolt-ons, and quite frankly, it's been a niche for us. The reason we showed the slide in the deck is to show just the number that we've done. If you think about our asset base, where it sits and the integrated nature of it, we're really uniquely positioned to be able to capture synergies. A lot of these bolt-ons aren't processes that formally come out, but it's more in discussions with our partners to see how do we get to win-win solutions. We've demonstrated that we can do that. These are bite-sized, but they certainly, when you add them up, make a meaningful difference and the returns are great on them. We think it's a great use of our free cash flow. We'll continue to try to advance and develop those. I think if you think about the environment where capital is tight, different partners have different constraints and desires. It's a target-rich environment for having discussions and the question is how many of them can you bring to fruition? 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. As we look at those, we're just going to stay very disciplined and if it makes sense for the unitholders to consider something like that, we would certainly be open. But in the meantime, I think the 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 seeing where there's available capacity. We're having constructive dialogues. I don't want to speak to specific pipes or interests. 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 and 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. A lot of capacity was built and the markets were tight, with spreads wide. We always expected at this point you would start tightening the spare capacity. The strategy on the long-haul extensions to 2028, 2029, and 2030 fit well, as well as retaining some open space to capture margins between Midland and the Gulf Coast. I think this strategy will pan out pretty well.

Got it. That's helpful. Thank you.

Thank you.

Thank you. One moment for the next question. Our next question comes from the 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 cost. You did mention it was part of the beat. So trying to understand what part of it is sticky and 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 were first half to second half deferrals.

Okay, and any quick commentary on the possibility of redeeming the preferreds, like 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 reevaluate that.

Thank you, guys.

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

Hi. Good morning. I think I clocked your prepared remarks at 6 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 in Q4 as the target?

Yes, 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 $2.20 increases. We've stated that $0.15 is an annual increase that we look at really 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 and producer consolidation. I think Jeremy alluded to relief when Matterhorn comes on. Just any thoughts just directionally for next year?

Willie here again. Although we haven't provided long-term guidance, I can share some general insights. We are focused on the long-term, and we believe the Permian will play a significant role globally. We expect our growth to align more closely with the range of 200 to 300 than with the exceptional growth figures we've experienced previously. There will be challenges and variability in our growth profile, but we are quite optimistic about the Permian, aided by technology and synergies from the consolidation of exploration and production companies, which will allow for more efficient development.

Thank you.

Thanks.

Thank you. One moment for the next question. Our next question comes from the 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 of what's open to contract here and help us sensitize how to think about the impact. As we think out to 2026 plus more pipeline capacity coming, what is your appetite to have 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-operating interest, so you might want to talk to one of them there. But Cactus I and Cactus 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. I noticed that the Permian intra-basin looks like that stepped up a bit, but gathering stepped down a bit. Sorry if I missed it, maybe if you could just walk us through the dynamic there and what's going on?

Sure. This is Jeremy again. It's largely associated with transportation to Colorado City to hit other connecting carriers to 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. Some of that's reflective of TMX. You see if the heavy barrels leave the Mid Continent, there are some other barrels that have to take its place. We've seen some impact on the basin, and 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 are added, as production goes, it finds new markets.

Got it. Helpful as always. Thanks, team.

Thank you. One moment for our next questions. Our next question comes from the 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 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 gear. 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 steeply backwardated and so opportunities are fewer and liquidity is lower on the 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. 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 some of the heavier gas cut wells that have been shut in or we've seen delayed turn in line wells? 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?

Neel, I think we're still in the range of 200,000 to 300,000 barrels a day and move within that range. But we have seen growth today, 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 had been. So you've seen even growth during the summer where maybe you didn't last year. Last year actually saw declines at this 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 has outperformed. I would say 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 the 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. I'm 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 at any ages that doesn't reflect an on-the-water number. 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 a disconnect. When you get into long-term contracting, you're looking over a five-year period, so the prompt doesn't impact the total rate. So what I'd 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. 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.

AJ, I think we've all experienced how forward curves are usually not good predictors of future prices. It's just a methodology to hedge and protect the future price. As Jeremy said, when you start running out of spare capacity, the pricing signals change different behaviors. 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, 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 spreads blew out in Q2 wider than historical norms. 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. While we don't forecast it in future periods, if it does, we'll turn it on, and we'll operate. I'd view that 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 the line of Sunil Sibal of Seaport Global. Your line is now open.

Yes. 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 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 systems? Should we expect a similar trajectory in volumes and cash flows from that system or should there be some expected changes? It 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 from me, it 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?

Yes, 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, we would expect in 2025 to see taxes come back off of this higher level.

Okay, thanks.

Thank you. 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. I don't think it changes our approach to be disciplined. It's got to be something where we can add significant value and compress multiple through synergies and our ability to operate. 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, typically, given the strip that you're seeing out there, do you plan to continue having the majority of C3 plus sales hedge going forward, or is there a scenario where you could take a bit more exposure?

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

Sir, you've done a nice job with this. Thank you.

Thank you. One moment for our next question. Our next question comes from the 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 if you can 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 Permian efficiencies, because we look at the back half of the year guidance, it kind of implies flat on second quarter versus we're talking about the fourth quarter step up here potentially, so just trying to unpack that cadence. Thanks.

Sure. I think Al spoke and Chris spoke to some of the operating expenses, lower utilities in the second quarter for movements on pipes where we have T&Ds 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 for the pieces that don't repeat the rest of the outperformance should repeat.

I appreciate that. Just one last one from me. We see the volumes elsewhere in crude outside the Permian kind of move around quarter-to-quarter. A lot of that is just kind of accounting of volumes and sums on the marketing side. But maybe if you could just give us a quick update on maybe just the run rate EBITDA generation off that footprint and maybe how that should trend over the next couple of years given we'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 production growth continues and that goes into a couple of our facilities today, and we expect that to continue. That's been a good surprise. 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 production. The rest has performed in line with expectations.

All right, I appreciate the time. Thank you.

Thank you. One moment for our 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 inland or just inland 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, Theresa. I put it in the second quarter roughly $15 million range, and then Q3 probably in 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 straddles. 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 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. 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 were lots of spare capacity and lots of infrastructure. I understand your question, but I would also want 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 the feedstock for alkylation for that demand. Turning to the cost commentary of cost deferred into the third quarter and maybe fourth quarter, any quantification or endpoints we should think about of how much that moved over?

Hi, Theresa, it's Chris Chandler. No is the short answer; 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 following years. There are 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 so…

Got it. Thank you very much.

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.