Good day, and Welcome to the Plains All American Pipeline Q2 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. To ask a question during the session, you will need to press star one one on your telephone. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker, Mr. Roy Lamoreaux. Please go ahead, sir. Thank you, Cherie. Good afternoon, and welcome to Plains All American Q2 2022 earnings call. Today's slide presentation is hosted on the investor relations website under the News and Events section at plains.com, where an audio replay will also be available following today's call. Important disclosures regarding forward-looking statements to non-GAAP financial measures are provided on slide two. An overview of today's call is provided on slide three. A condensed consolidating balance sheet for PAGP and other reference materials are located in the appendix. Today's call will be hosted by Willie Chiang, Chairman and CEO, and Al Swanson, Executive Vice President and CFO. Other members of our team will be available for the Q&A, including Harry Pefanis, President, Chris Chandler, Executive Vice President and Chief Operating Officer, Jeremy Goebel, Executive Vice President and Chief Commercial Officer, and Chris Herbold, Senior Vice President of Finance and Chief Accounting Officer. With that, I will now turn the call over to Willie. Thank you, Roy. Good afternoon, and thank you all for joining us. Today, we announced Q2 results above our expectations, reflecting continued execution of our long-term goals and initiatives, as well as strength in both of our crude and NGL segments. In summary, Q2 Adjusted EBITDA attributable to PAA was $615 million. We increased our full year 2022 Adjusted EBITDA guidance by $100 million to ±$2.375 billion, which is $175 million above our initial February guidance. This was driven by outperformance in both of our NGL and crude oil segments due to higher volumes and higher commodity prices. As a result, we now expect to achieve the midpoint of our leverage target range of 4.0 times by year-end 2022. In regards to buybacks, we repurchased approximately $50 million of common units during the quarter, bringing our year-to-date repurchases to approximately $75 million and total repurchases of $300 million since the program inception. Additionally, we're increasing our 2022 asset sales target by $100 million as a result of greater clarity on asset sales that we anticipate to complete during the balance of the year. Al will provide more detail on our quarterly results and our full year outlook in his portion of the call. As highlighted on slide four and five, the overall fundamentals of our business remain constructive as North American shale remains key to meeting global energy demand. Current activity levels in the Permian are running roughly 10% ahead of our forecasts, and we expect to see between 650,000 and 700,000 barrels a day of production growth exit to exit during 2022. Our operating leverage and integrated business model with large scale supply aggregation, quality segregation, flow assurance, and access to multiple markets has positioned us well to support increasing producer activity levels. Both our crude and NGL systems have meaningful capacity to grow alongside of the needs of our customers for the next number of years, and we are well-positioned to capture incremental volumes with minimal capital investment. At the beginning of July, our Permian Gathering JV closed on a bolt-on acquisition for the remaining 50% ownership interest of the Advantage Pipeline for approximately $65 million or $42 million net to Plains interest, plus customary closing costs. The negotiated transaction provides the JV additional operational, commercial, and capital synergies at an attractive multiple. The acquisition costs associated with this bolt-on opportunity are more than offset by the incremental proceeds expected from the previously mentioned increase in 2022 asset sales. In our NGL segment, we continue to advance capital efficient optimization and debottlenecking opportunities at our existing facilities. Furthermore, we expect growing Western Canadian gas production to drive incremental cross-border gas flow volumes towards our strategically located Sarnia facility. With regard to our financial strategy, we expect to continue to generate significant free cash flow over the next number of years, and we intend to allocate this cash in a manner that takes into account the progress that we've made to date on our leverage while increasing cash return to equity holders through distribution growth and opportunistic buybacks, as well as continuing to make disciplined capital investments. As I noted in my opening remarks, we've made significant progress in strengthening our balance sheet. We entered the year with leverage at 4.5 times and with the expectation of finishing 2022 at the high end of our target of 4.25 times. We now expect to exit the year at the midpoint of our target, which is 4.0 times. The improved trajectory allows us to further accelerate our goal of increasing return of capital to our unitholders over the coming years. Before turning the call over to Al, I'd like to mention that we published our 2021 sustainability report last week. As reflected on slide 25 of the appendix, we've made continuous improvements in our emissions and advanced sustainability in many areas of the company. We're proud of these achievements, and we look forward to continuing the dialogue with many of you on our sustainability performance. With that, I'll turn the call over to you, Al. Thanks, Willie. We reported Q2 Adjusted EBITDA of $615 million, which includes the benefit of higher straddle plant volumes at Empress due to increased gas border flows, elevated commodity prices benefiting our pipeline loss allowance revenue and higher volumes on our Permian Basin long-haul pipelines, primarily flows on Basin Pipeline to Cushing. Slide 16 and 17 in today's appendix contain quarter-over-quarter and year-over-year segment Adjusted EBITDA walks, which provide more detail on our Q2 performance. A summary of our 2022 guidance is located on slide six through nine. We've increased our full year 2022 Adjusted EBITDA guidance by $100 million to ±$2.375 billion. Our updated guidance is $175 million above our initial February estimates, largely as a result of higher commodity prices and frac spreads benefiting our C3+ spec product sales and volumes in our NGL segment, as well as increased prices on pipeline loss allowance barrels and incremental Permian volumes in the crude oil segment. We remain focused on disciplined investments, and our outlook is summarized on slide 10. This is consistent with our May guidance, and we do not anticipate any meaningful changes in our capital program for the balance of the year. I also want to share a few comments on how inflation impacts our business. Generally speaking, our inflation impacts are more moderate than some of the other energy sectors. Our capital program is modest, and we have proactively managed some costs through earlier purchases of materials. As expected, fuel and energy prices are higher as a result of the higher commodity prices, and we are seeing increased pricing on equipment, materials and services, which we are mitigating through strategic sourcing, utilizing bulk orders and rebidding. All of this being said, we continue to expect annual escalators to offset expenses and provide a modest net benefit. On capital allocation, our framework remains consistent. We are generating meaningful free cash flow and increasing the allocation to equity holders while reinforcing balance sheet strength and flexibility. Year-to-date, we have repurchased approximately $75 million of common units out of the up to $100 million or so we earmarked for 2022. Longer term, we will continue to be opportunistic with repurchases as we monitor our business outlook, leverage equity valuation and yield, as well as discipline future capital investment opportunities. A summary of our current financial profile is located on slide 11. With that, I will turn the call back over to Willie. Thank you, Al. Today's results reflect another solid quarter of performance and execution. Fundamentals remain constructive, and our asset base and business continue to perform well in the higher commodity price environment, capturing incremental growth via the operating leverage within our system. Looking forward, we continue to build momentum into 2023, and Plains is very well positioned to generate meaningful cash flow to the benefit of our investors. Over the last few years, we've made solid progress on optimizing our assets, completing our multi-year capital build-out, forming numerous strategic JVs, including the Plains Oryx Permian JV, and continuing to improve our safety, environmental and sustainability performance. Additionally, as we've detailed in our remarks, we've continued to improve our balance sheet and have increased capital return to unit holders. Given the acceleration of our de-leveraging and improved financial flexibility, we plan on having discussions regarding our capital allocation framework with our board of directors, and I look forward to sharing additional thoughts with you in the coming quarters. In summary, we've accomplished numerous initiatives over the last few years, and we believe our business is very well positioned today and going forward. A summary of our execution and positioning as well as key takeaways from today's call are provided on slides 12 and 13. With that, I'll turn the call back over to Roy to lead us into Q&A. Thanks, Willie. As we enter the Q&A session, please limit yourself to one question and one follow-up question, then return to the queue if you have additional follow-ups. This will allow us to address the top questions from as many participants as practical in our available time this evening. Additionally, our investor relations team plans to be available throughout the week to address additional questions. Cherie, we're now ready to open the call for questions. Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone. Please stand by while we compile the Q&A roster. Our first question will come from Jean Ann Salisbury with Bernstein. Please go ahead. Hi. Utilization on crude pipes to Corpus has been very high year-to-date, higher than Houston or Cushing. Do you forecast this staying for the foreseeable future? What could change that? Jean Ann, this is Willie. You know, we've articulated our system as being very flexible. As we think about our system, we've got capacity down to the coast through Cactus One, Cactus Two, and Basin. The point I wanted to make is whether or not volumes are flowing directly down to Corpus doesn't necessarily reflect the power of the business because volumes can be going up to Cushing. Jeremy, do you wanna cover some more details on her specific question? Yeah. Jean Ann, with regard to Corpus, the marginal demand right now is in the international given the disruption to the supply chains for crude oil. We would expect to see utilization to the most efficient export markets. Corpus is pricing at a premium to Houston to other export markets. Naturally, the highest price is gonna attract barrels plus the quality of the barrel. I think we'll see more of that, but as those lines fill, it starts to lead to higher utilization in other markets. As we get through this year, you'll see Corpus remain high, and then you'll see additions to other markets. You'll see some additional ramps and other pipes next year. This is step one because it's the highest price. You'll see that, but as it fills, the whole boat will start to fill. To answer your question, yes, we would expect Corpus. It's pricing at a premium from a quality and then a logistics standpoint. Jean Ann, Willie again, you know, as production continues to grow in the Permian, and as we expect it to, by definition, we expect more volumes to go into our long-haul lines. As you probably saw in one of the slides, we do have increases in our outlook for volumes that are flowing both in the long-haul intra-basin and some of the other systems. Yeah. No, I did see that. Is it fair to say, though, that you would prefer a barrel on Cactus or Cactus two versus a barrel going to Cushing in terms of margin, or it just depends? Based on ownership, we're kind of even. The margins to Corpus have been better, but the margins at Cushing continue to bounce and are getting higher, and there's more demand for that over the longer term, as we'll see. I'd see on an absolute margin standpoint, just because of ownership of basin relative to the others we're somewhat indifferent between the two on even if it's a slightly lower tariff to Cushing because we own 100% of our basin capacity versus what effectively with Eagle Ford JV is 75% and then 65% on Cactus Two. When you think of the economics, we're somewhat indifferent, but barrels moving, customers happy, full pipelines are good for us. Jean Ann, back on the flexibility just to reinforce the point. You know, currently as utilization increases on the pipelines, the tariffs will increase as well. And as we shared last time, you know, the forward market still has some pretty constructive spreads in there that we've been able to to utilize. So what we say today may change as we go forward. If you've got a much higher tariff to Cushing, obviously the barrel going to Cushing may make more sense. But again, think of our system as a very flexible system that allows it to go to multiple markets. Great. I'll leave it there. Thank you. Thanks, Jean Ann. Thank you. One moment for our next question. That will come from the line of Keith Stanley with Wolfe Research. Please go ahead. Hi, good evening. First on the NGL segment, can you say how much of the guidance uplift in EBITDA for the year is volume driven versus margin? I'm curious, you've seen higher volumes through Empress. I know you're working on other commercial and debottlenecking activities. Could there be a lot more movement in terms of volumes and building out that business over time? Yeah. I'll let either Jeremy or Al give you a view on the difference between price and volume. I can tell you it was both. We had some unique events in the Q2 as far as weather problems in the Bakken that allowed more flows going that way, but the fundamental volumes are also higher. You are correct, Keith. As we think about Empress, we've got some low cost debottlenecking opportunities there, and as we've shared with you before, we clearly are trying to optimize the entire complex commercially so that we can optimize more of that. Jeremy or Al, do you wanna talk about dollars on price versus volume? Yeah, sure. Your direct question is based on where we forecasted our weighted average frac spread between hedging and market pricing. I think that's gonna end up around 40% price, 60% volume, for this year. That's a proxy. I don't necessarily have the exact one on hand, but I think that's gonna be fairly close. As far as border flow capacity, us and Pembina have the vast majority of the capacity in the Empress complex, essentially all of it. We have some room for expansion through the systems, some optimizations that we've recently announced. Incremental border flows from west to east will largely go to Plains' capacity from here on out. As incremental production comes on net of what gets exported to the West Coast, those movements, as long as the arcs continue and as you create more demand out of the Marcellus to move to other markets, you would expect more gas to go from the AECO markets that are lower priced than U.S. markets. Effectively, that's the mechanism. It does compete some with Bakken production. You've seen some of the uplift in the Q2 was due to weakness in Bakken production. By and large, anything that's moving west to east on the TransCanada system to fill voids across that arc would go through that Empress complex, and we have substantial capacity to extract additional NGLs. You know, Chris Chandler, you may talk about just generally speaking, we haven't finalized investment decisions on this, but we've got a number of things that we're trying to advance as far as debottlenecking Empress. Chris, you want to chat about that? Sure, Keith, this is Chris. What we really like about Empress is there's capacity on the gas system to move more gas through, as Jeremy stated. There's capacity in the extraction plants themselves, the straddle plants, to extract the NGLs today, so that provides some operating leverage and upside. From a debottlenecking standpoint, it's really about where we fractionate the NGLs. Today we fractionate a portion at Empress, and we ship the rest over to our Sarnia, Ontario fractionator. That gives us access to both those markets. We are Evaluating projects to do additional fractionation at Empress to be able to distribute the purity products directly out of the Empress or the regional area instead of having to ship them and the associated cost, over, to the east, into Ontario to further fractionate there. A lot of opportunity around both capacity and efficiency and debottlenecking for that entire complex. Keith, the value, the dollar value of this is measured in $10s of millions, not $100s of millions. They're very low cost, high return opportunities if we proceed with them. Thanks. That's very thorough and helpful. Second, unrelated question. On the Inflation Reduction Act, you obviously have the unique structure with PAGP. What's your initial read on, you know, who knows if the bill will pass and the minimum tax component, but as it's written right now, what's your initial read on what it could mean for PAGP and if it would apply to that security or not? Keith, this is Al. Our read would be it would not apply. I believe that as contemplated, it's if you have income, net income over $1 billion, PAG is much smaller than that. We do not believe it would apply. You know, if you stand back, ultimately, we think our structure, you know, as an MLP, if corporate tax rates go up, the MLP, you know, obviously isn't an issue there. Ultimately, PAGP has, you know, a very large tax asset there that the entity won't be paying corporate taxes for a while. We think this issue with this minimum tax does not apply to PAGP. Great. Thank you. Thank you. One moment for our next question. That will come from the line of Colton Bean with Tudor, Pickering, Holt & Co. Please go ahead. Afternoon. You mentioned the potential to increase equity returns a number of times. I know it's still early in the decision-making process, but at a high level, would you expect to see the equity allocation of excess free cash flow move toward 100% if you drop towards the lower bound of your leverage range? Or is there also potential to see the leverage range shift lower altogether? You know, Colton, I would, I'd rather give you a more detailed update after we have some discussions with our board. You know, when we think about capital allocation, a couple things. We actually, we have an annual process, that we have with our board, happens early in the year usually, and we announce, in April with the distribution increase in May. With the progress that we've made on deleveraging, and our momentum that we're building into 2023, it gives us an opportunity to look at this a little closer. I think what you'll see is, as we go forward, it's gonna be a lot of the things you mentioned, we're gonna evaluate where do we want our leverage ultimately. We expect to be at our target. Do we migrate down a little further? Also, you know, you can expect us to continue our discipline as far as CapEx and investments. The real question on capital allocation is the split between distribution increase and buybacks. I think you'll see that we will continue to support distribution increases. I won't give you specifics on that, because again, we have to have some conversation with our board. I would expect that the buybacks will continue to be opportunistic. Understood. Following up on the NGL discussion, are you also seeing any benefit from wider basis spreads, particularly that eastbound movement to Sarnia? Is it primarily the frac spread that's driving the upside? The answer is all of the above. We do manage our sales similar to our hedging. There's some will be locked in at fixed differentials, but there's always an opportunistic component. We can accelerate sales into opportunistic sales. We do sell forward at fixed basis differentials. When markets are short, we certainly have the ability to sell at Edmonton. We have the ability to rail out of the Empress facility. We have the ability to rail out of the Sarnia facility or sell locally there. There's a ton of flexibility in where we market and how. For instance, if Sarnia is a better market, you can sell locally there. If Conway, like certain instances now, we see that opportunity, we can wheel barrels to that location. It's a very flexible system. Ethane, we have similar capabilities across it if California is short or other markets. You'll see us absolutely optimize sale and basis. By and large, the frac spread is the biggest component, but basis can at times have real market structure changes that would incentivize us to move additional barrels, too. Got it. Appreciate the detail. Thank you. One moment for our next question. That will come from the line of Chase Mulvehill with Bank of America. Please go ahead. Hi, this is Neel Mitra filling in for Chase. I wanted to understand the contracting opportunities for Basin, Cactus I and Cactus II just recently given the high year-to-date volumes. Are you seeing any attractive blend-and-extend opportunities, or is the timeline just too short-lived with low Cushing inventories at Basin and you know the strong international demand given the Russia-Ukraine conflict? Did people need to see a wider basis for longer for you to extend, and what's the appetite for that? Thanks, Neel. This is Jeremy. What I would say is we are constantly in the market with our gathering customers, with our long-haul customers and in those dialogues. While spreads were $0.40, now $0.60, moving to $0.80, then $1.20, we've been watching that along the way. We didn't wanna do any long-term deals at those periods. The time for blend and extend is when the producers are short cash. Now they're flush cash, so they really don't look at blend and extend. It's more of looking secure takeaway at an appropriate price. We're in that dance with what's the appropriate price. We're very active. There's been a lot of demand in extending some deals into Cushing or getting long-haul to and discussions around some Cushing contracts, securing supply. We're in discussions around Corpus contracts. When there's something to update, we absolutely will, but we're constantly managing the duration of our contracts but we wanna maximize the value, and we're confident in the production profile we have this year and the momentum next year. There's a better time when the prompt is $0.60 to negotiate longer term deals. As we talked about in the last call, 2024 is still staying around that $1.25 range with a premium for Corpus markets. We'll continue to look to optimize that space and have discussions with our existing shippers and other shippers as well. Great. Go ahead, Neel. Sorry. Yeah. I just wanted to ask a follow-up to that, Jeremy. A lot of your peers have talked about Midland to Houston pipes, producers not utilizing them and actually paying deficiency fees to move to alternative locations, which are presumably Corpus and likely Cushing as well. Given that you have interest in almost all of the long-haul pipes out of Midland, can you just describe, you know, in the current market, what's going on and maybe how that impacts where Plains' volumes are going? Yeah. What I would say is there's a lot of volatility in flat price and location differentials between Brent, WTI, MEH, Midland, which creates a lot of difficulty in pricing barrels. A lot of the election to not move to the end market is to sell at Midland. People see opportunities. It's better to just clear at Midland than do that, especially with backwardation and long-haul shipments and exports. That adds complexity. It's a long-winded way to answer. It's a very complicated process to price cargoes. That's why you see a lot of volatility in people pricing because they can't find markets. With the backwardation, they have to hit the exact window, and people are losing substantial volumes. Some are more equipped to have different markets, so they sell at Midland, another person moves on a pipe. As I said in the beginning, Corpus for the market for exports is proving to be more efficient. It has a better price, a better quality, and you're seeing a lot of barrels move in that direction. Houston is moving substantial volume. There's just a lot of capacity to thereafter Wink to Webster, so you're seeing some more slack there. Pricing these things is complex, and you'll see a lot of cargoes move in a few days in a month, and then you won't see any move for a period when the prices get out of whack. It's a constantly fluid situation, but price usually wins. Right now, Corpus is the best price with low inventories and high crack spreads. Cushing has to move barrels, so you've seen some more demand on the Basin system since there's not inventories to pull from. The Houston refining and the base export business, you're seeing pretty consistent volumes. You're just seeing a displacement of volume from one pipe to the other. Neel, the key takeaway on this that Jeremy's been talking about is remember, we've got strong MVCs on these lines. Whether or not a volume flows there or not, we still get paid, and it gives us the opportunity to further optimize it. Right. Appreciate all the color. Thanks. Thank you. Thank you. One moment for our next question. Our next question will come from the line of Brian Reynolds with UBS. Please go ahead. Hi. Good evening, everyone. You talked about in your prepared remarks running 10% above expectations, I think, on a volumetric perspective. You know, kind of curious if you can just talk about how you're attracting volumes to the system and if you could help bifurcate what you're seeing from organic growth and perhaps attracting new volumes and customers to the system, you know, from competitors. Thanks. I'm gonna let Jeremy answer this, but I wanna preface it with, it's a very complicated system. Because we've got the gathering JV, we've got intra-basin, we've got long haul, there's a lot of moving parts on this. Jeremy, take a shot at it. Sure. Brian, first answer to clarify what Willie was saying is a 10% increase in activity across the system. Activity translates to volumes later in the year. For instance, we think the production growth is back-loaded, weighted completions of 40% in the first half, roughly 60% in the second half. That activity is gonna yield some momentum in the second half of the year going into 2023. I just wanted to first clarify that. How are we doing competing for volumes? We have over four million dedicated acres between the Oryx and Plains systems, the POP JV that we have. We continue to have happy customers and are extending deals. We're actually adding substantial acreage to the position, core acreage for significant term. I think we're competing very well, and we're not pricing to the lowest common denominator due to the flexibility, the quality control, and the market access that we have on the system. What I would say is that we're competing very well for incremental and organic volume. When you have term acreage dedication, you have contracts that bring a substantial amount of activity to the system. Not everything has to be organically developed when you have the contract tenor that we have. This is just additive to the base business that we put together when we merged the two businesses. I think, Brian, if you look at slide seven it would probably give you a little more insight into the volumes and how we're getting it across the system in the Permian between gathering, intrabasin and long-haul. Great. Appreciate all that clarification and extra color. As I want to follow up, could you just talk about what you're seeing in terms of Eagle Ford volumes? Saw a small tick down during the quarter, but, you know, it seems like the Eagle Ford, you know, is attracting more rig count and activity to the system. Kind of curious if you can talk about, you know, further expectations there. Thanks. Jeremy? Sure, Brian. You've seen a lot of turnover from public operators to private operators in the Eagle Ford, and that generally leads to more activity, because those activities were starved for capital, given that there was more allocation to the Permian or somewhere else. You've seen Chesapeake, say, Encore. What I would say is we have seen more activity. The newer buyers come in, and they're accelerating activity. We've seen that in the Western Eagle Ford with the Chalk as well as the lower Eagle Ford. I'd say we are seeing an increase in activity in the Eagle Ford, and it seems to be as they prove up the Chalk in the Western Eagle Ford, we would expect to see continued growth in volume there. Great. Appreciate all the color. Have a good rest of your evening, everyone. Thanks, Brian. Thank you. One moment for our next question. That will come from Jeremy Tonet with J.P. Morgan. Please go ahead. Hi. Good afternoon. Hi, Jeremy. Good afternoon. Thanks. Just want a quick refresher, if I could. I think you talked about in the past points where volume growth on the system would move you past MVCs and it would turn into more, you know, fall to the bottom line, be growth at that point. What's the current timeline there? Has that moved forward at all with this? Or just a refresh there would be great. You know, I think the refresh would be, Jeremy, look at our numbers for the quarter and the additional volumes we've been able to bring in. The system is flexible. The gathering system grows with the basin, so those volumes continue to grow. On the long-haul, you'll see that the long-haul volumes, we've been able to get some more volumes on that. The difference between last quarter's estimate and this quarter's estimate, which is on the slide, really shows the increase in the system. Jeremy, anything to add? No, Jeremy. I think Willie's right. As you accelerate production and momentum, you bring that time period forward. Because as we said, every time you add 600,000 or 700,000 barrels a day of production, you're filling a pipe. If you think about that, it's still consistent with the 18-24 months that we talked about, but it's accelerating as we accelerate our forecast, and we feel good about the momentum going into next year. That's proving out as you look at the differentials to the coast. They're getting outside of tariffs beginning in 2024. It's very consistent with what we said, and it's continuing to progress along, and we're looking forward to that period. Got it. Summing together, maybe that's a mid-2023 timeframe if it's slightly quicker than before, if I'm gonna ballpark it. Sure. I mean, that's a very reasonable estimate. I'd say you can get into that period and you start to see a better utilizations and it's a It strikes a better balance between the carriers and the producers for a reasonable rate of return on the pipes. Jeremy, just to make sure, we're saying the same thing. I agree with what Jeremy Goebel said, but our system, because of the flex, allows us to capture some of the. We don't have to wait for that period of time to be able to capture volumes. Hope that's clear. Got it. Thanks. Just one last one, if I could. If I'm looking at the guidance increase now versus May, what's the breakdown between fee versus commodity there? It's a tough. Al, can you give the numbers? They're all tied to higher commodity prices, but there's definitely some volume components of it. Yeah. There's one slide that we did a walk for the year from the beginning of the year. Most of the driver is commodity, whether it's the NGL frac up in Canada. As Jeremy mentioned earlier, we are seeing some volume benefit there as well. Then on the crude oil side, which has actually been a smaller part of the increase, it's driven by, you know, the PLA pricing, but also this Permian volume growth that we're seeing and is embedded in. I would say over half of it is more commodity-based, and the rest I would say would be more fee-based. Got it. I'll leave it there. Thank you. Thanks, Jeremy. Thank you. One moment for our next question. That will come from the line of Sunil Sibal with Seaport Global. Please go ahead. Yes. Hi, good afternoon, folks, and thanks for all the clarity on the call. A couple of questions for me. You know, starting out on your asset sales program, the updated number, $200 million. Is that, you know, entirely a function of bringing more assets into the program or just a function of the market also? It's really developing better clarity on what assets. We've been visiting with folks about different assets, and it's just more clarity on being able to bring that across the line this year, Sunil. Okay, got it. I think you folks mentioned about, you know, some impact of the outages in Bakken, in terms of, you know, your NGL assets in Canada. I was kind of curious, have you seen that a bit or that's something, you know, you kind of still expecting a benefit from the remainder of the year? Jeremy? Sunil, hi. This is Jeremy. As the Williston production went down, crude oil production, gas production went down. That normally feeds to the Midwest. More gas was needed from AECO storage. That was temporary in April and May, but we're still seeing high border flows and high production. Canadian production's approaching 14 Bcf a day. You've got AECO prices hovering between $4 and $5, which is incenting additional drilling. Those are all positive for incremental border flows. That portion is sustained, but just some portion of the April-May, the Q2 outperformance was driven by that, but a substantial portion was driven by better activity in the gas plays within Canada. Okay, got it. Thanks for that. Thanks, Sunil. Thank you. One moment for our next question. That will come from the line of Neal Dingmann with Truist. Please go ahead. Good evening, guys. Thanks for the time. My first question's on M&A, and specifically, I was curious as to how do you view today's market of existing potential available assets versus, you know, I know you've got a lot of room for potential expansion or other, what I consider sort of organic-type build-out. Wonder how you sort of view these two things? Well, we look at a lot of assets that are out there, and we're gonna stay very disciplined on it. The bid-ask spread, I would say, is coming in a bit. Jeremy? Sure. On the crude side, the market's not as deep as on the liquids or the gas side, but we're gonna remain disciplined and we'll see opportunities. The footprint we have affords us an ability to extract more synergies than most from a capital standpoint, from an operating expense standpoint, and from a commercial standpoint. We'll be disciplined. We'll look for opportunities. We're constantly engaged in dialogue, but we're only gonna do things if they're near-term cash flow accretive and longer-term beneficial for the overall system. Great to hear. Then just a quick second one. I was just trying to get a broad sense of how much of the total intra-basin Permian growth. I know you mentioned there a good bit of this is likely to be coming from that recent Advantage JV. I'm just trying to get a sense in broad terms, is it you know, more for housekeeping, is that a large percent or, you know, just trying to get an idea of how much that Advantage will be contributing? To give you a sense, Advantage 50% that we acquired was roughly 30,000-35,000 barrels a day. That'll give you a sense from a gross basis what will come back to us. We have the ability to move barrels from other directions and put them on that pipe and eliminate future capital expenditures moving from west to east by displacing those volumes. I think we have the ability to put additional volume and eliminate or defer significant capital expenditures. I think that's part of the allure is to have that pipe at idle capacity that we can use to more efficiently operate our system. Greatly helped, Jeremy. Thanks, guys. Thanks, Neal. Thank you. I'm showing no further questions in the queue at this time. I would now like to turn the call back over to management for any closing remarks. Thanks, Cherie. Well, listen, thanks to everyone for joining us today. We'll look forward to visiting with you, going forward. Thanks for your continued interest and support for Plains All American. Have a nice evening. This concludes today's conference call. Thank you for participating. You may now disconnect.