Good day, and welcome to the Plains All American Pipeline Second Quarter Earnings Call. [Operator Instructions] 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, Sheri. Good afternoon, and welcome to Plains All American Second Quarter 2022 Earnings Call. Today's slide presentation is posted on the Investor Relations website under the News and Events section of plains.com where 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 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, 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 second quarter 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, second quarter adjusted EBITDA attributable to PAA was $615 million. We increased our full year 2022 adjusted EBITDA guidance by $100 million to plus or minus $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 4.0x 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 4 and 5, the overall fundamentals of our business remain constructive as North American shale remains keen in 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…

Thanks, Willie. We reported second quarter adjusted EBITDA of $615 million, which includes the benefit of higher straddle plant volumes at Empress due to increased gas order 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 second quarter performance. A summary of our 2022 guidance is located on Slides 6 through 9. We've increased our full year 2022 adjusted EBITDA guidance by $100 million to plus or minus $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 at 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. We monitor our business outlook, leverage equity valuation and yield as well as disciplined 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 multiyear 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 unitholders. Given the acceleration of our deleveraging 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. [Operator Instructions] Sheri, we're now ready to open the call for questions.

[Operator Instructions] Our first question will come from Jean Ann Salisbury with Bernstein.

Utilization on crude pipes to Corpus has been very high year-to-date, higher than Houston and Cushing. Do you forecast this staying for the foreseeable future? Or what could change that?

Jean Ann, this is Willie. We've articulated our system as being very flexible. So as we think about our system, we've got capacity down to the coast through Cactus I, Cactus II in Basin. And 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 want to cover some more details on her specific question?

Jean Ann, with regard to Corpus, the marginal demand right now is in international, given the disruption of the supply chain for crude oil. So we would expect to see utilization to the most efficient export markets. Corpus is pricing at a premium to Houston to other export markets. So naturally, the highest price is going to attract barrels plus the quality of the barrel. So I think we'll see more of that. But as those lines fill, it starts to lead to higher utilization in other markets. So 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 in other pipes next year. So this is step 1 because it's the highest price. And so you'll see that. But as it fills, the whole boat will start to fill. So -- but to answer your question, yes, we would expect Corpus is pricing at a premium from a quality and on a logistics standpoint.

And Jean Ann, Willie again, as production continues to grow in the Permian as we expect it to, by definition, we expect more volumes to go into our long-haul lines. And 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.

Yes, no added to that. Is it fair to say though that you would prefer a barrel on Cactus or Cactus II versus a barrel going to Cushing in terms of margin or just it 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. But see, on an absolute margin standpoint, just because of ownership of Basin relative to the others, we're somewhat indifferent between the 2 on -- even if it's a slightly lower tariff to Cushing, because we own 100% of the -- our Basin capacity versus what effectively with the Eagle Ford JV is 75% and then 65% on Cactus II. So when you think of the economics, we're somewhat indifferent, but barrels moving, customers happy, full pipelines are [indiscernible].

And Jean Ann, back on the flexibility just to reinforce the point. Currently, as utilization increases in the pipelines, the tariffs will increase as well. And as we shared last time, the forward markets still has some pretty constructive spreads in there that we've been able 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 us to go to multiple markets.

One moment for our next question. That will come from the line of Keith Stanley with Wolfe Research.

First, on the NGL segment. Can you say how much of the guidance uplift in EBITDA for the year is volume driven versus margin? And then 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?

Yes. I'll let either Jeremy or Al give you a view on the difference between pricing and volume. I can tell you it was both. We had some unique events in the second quarter as far as weather problems in the Bakken that allowed more flows going that way, but the fundamental volumes are also higher. And 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 want to talk about dollars? Price versus...

Yes, sure. So your direct question is based on where we forecasted our weighted average frac spread between hedging and market pricing, I think that's going to 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 going to 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. And we have some room for expansion through the systems, some optimizations that we've recently announced. And so incremental border flows from west to east will largely go to Plains' capacity from here on out. So as incremental production comes on net of what gets exported to the West Coast, those movements, as long as the arbs 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 in U.S. markets. So effectively, that's the mechanism. It does compete some with Bakken production. So you've seen some of the uplift in the second quarter was due to weakness in Bakken production. But by and large, the -- anything that's moving west to east on the TransCanada system to fill voids across that arb would go through that Empress complex. And we have substantial capacity to meet that existing -- to extract additional NGLs.

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. And then from a debottlenecking standpoint, it's really about where we fractionate the NGLs. So 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, but 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. So a lot of opportunity around both capacity and efficiency and debottlenecking for that entire complex.

And Keith, the dollar value of this is measured in tens of millions, not hundreds of millions. So they're very low cost, high return opportunities if we proceed with them.

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 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 doesn't -- is much smaller than that. So we do not believe it would apply. If you stand back, ultimately, we think our structure as an MLP, if corporate tax rates go up, the MLP obviously isn't an issue there. Ultimately, PAGP has a very large tax asset there that if the entity won't be paying corporate taxes for a while. But we think this issue with this minimum tax does not apply to PAGP.

One moment for our next question. That will come from the line of Colton Bean with Tudor, Pickering Holt.

So 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 a potential to see the leverage range shift lower altogether?

Colton, I'd rather give you a more detailed update after we have some discussions with our Board. When we think about capital allocation, a couple of things. We actually -- we have an annual process that we have with our Board. It 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. And I think what you'll see is, as we go forward, it's going to be a lot of the things you mentioned. We're going to evaluate where do we want our leverage ultimately. We expect to be at our target. We might rate down a little further. And then also, you can expect us to be -- to continue our discipline as far as CapEx and investments. And then the real question on capital allocation is the split between distribution increase and buybacks. And 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, but I would expect that the buybacks will continue to be opportunistic.

Understood. And then following up on the NGL discussion. Are you also seeing any benefit from wider basis spreads, particularly that east down movement to Sarnia? Or is it primarily the frac spread that's driving the upside?

The answer is all of the above. So we do manage our sales similar to our hedging. So there's some will be locked in at fixed differentials, but there's always an opportunistic component. We can accelerate sales into opportunistic sales. So we do sell forward at fixed basis differentials. But when markets are short, we certainly -- we 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. So there's a ton of flexibility in where we market and how. So 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. So it's a very flexible system. Butane, we have similar capabilities across it of California shore or other markets. So you'll see as an absolutely optimized sale and basis. But by and large, the frac spread is the biggest component, but basis can be at times have real market structural changes that would incentivize us to move additional barrels to them.

One moment for our next question. That will come from the line of Chase Mulvehill with Bank of America.

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 time line just too short lived with low Cushing inventories at Basin and the strong international demand given the Russian-Ukraine conflict that people need to see a wider basis for longer for you to extend? 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. So 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 want to do any long-term deals at those periods. The time for blend-and-extend is when the producers are short cast. Now they're flushed with cash. So they really don't look at blend-and-extend. It's more of looking secure takeaway at an appropriate price. And so 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 we're in 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 and -- but we want to maximize the value, and we're confident in the production profile we have this year and the momentum next year. And there's a better time when the prompt is $0.60 to negotiate longer-term deals. But the -- but as we talked about in the last call, 2024 is still staying around that $1.25 range with a premium for Corpus markets. And so we'll continue to look to optimize that space and have discussions with our existing shippers and other shippers as well.

I just wanted to ask a follow-up to that, Jeremy. So 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 in the current market, what's going on and maybe how that impacts where Plains' volumes are going?

Yes. What I would say is there's a lot of volatility in flat price and location differentials between Brent, TI, MEH, Midland, which creates a lot of difficulty in pricing barrels. So 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. So it's a long-winded way to answer. It's a very complicated process to price cargoes. So that's why you see a lot of volatility in people pricing because they can't find markets. And with the backwardation, they have to hit the exact window and people are moving substantial volumes. So some are more equipped to have different markets. So they sell at Midland, another person moves on a pipe. But 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. But pricing these things is complex. And you'll see a lot of cargoes moving a few days in a month, and then you won't see any move for a period when the prices get out of whack. So it's a constantly fluid situation, but price usually wins and 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. And then 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.

And Neel, the key takeaway on this that Jeremy has been talking about is, remember, we've got strong MBCs on these lines. So whether or not a volume flows there or not, we still get paid. And it gives us the opportunity to further optimize it.

Our next question will come from the line of Brian Reynolds with UBS.

You talked about in your prepared remarks, running 10% above expectations, I think, on a volumetric perspective. Kind of curious if you can just talk about how you're attracting volumes to system. if you could help bifurcate what you're seeing from organic growth and perhaps attracting new volumes and customers to the system from competitors?

I'm going to let Jeremy answer this, but I want to preface it with it's a very complicated system. And 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. So Jeremy, take a shot at it.

Sure. Brian, first to clarify what Willie was saying is a 10% increase in activity across the system, activity translates to volumes later in the year. So for instance, we think the production growth is back-end weighted. Connections are 40% in the first half, roughly 60% in the second half. So that activity is going to yield some momentum in the second half of the year going into 2023. So I just wanted to first clarify that. But how are we doing competing for volumes? We have over 4 million dedicated acreage 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. So 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. So what I would say is we're competing very well for incremental and organic volume. But when you have term acreage dedication, you have contracts that bring a substantial amount of activity to the system. So 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 2 businesses.

I think, Brian, if you look at Slide 7, it would probably give you a little more insight in the volumes and how we're getting it across the system of the Permian between gathering, intra-Basin and long haul.

Great. I appreciate all that clarification and extra color. As my one 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 it seems like the Eagle Ford is attracting more rig count and activity. So I'm kind of curious if you can talk about further expectations there.

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. Those activities were starved for capital given that there was more allocation to the Permian or somewhere else. And so you've seen Chesapeake say it's noncore. So 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. So 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.

One moment for our next question. That will come from Jeremy Tonet with JPMorgan.

Just want a quick refresher, if I could. I think you talked about in the past points where volume growth on the system [ with movie pass ] MBCs and it would turn into more -- fall to the bottom line, beat growth at that point. Do you -- what's the current time line there? Does that move forward at all with this? Or just a refresh there would be great.

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. And then on the long haul, you'll see that the long-haul volumes, we've been able to get some more volumes on that. And 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 is 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 the pipe. So if you think about that, it's still consistent with the 18 to 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. And that's proving out, as you look at the differentials to the coast, they're getting outside of tariffs beginning in 2024. So 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. So summing together, maybe that's a mid '23 time frame, if it's slightly quicker than before, if I'm going to 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 strikes a better balance between the carriers and the producers for a reasonable rate of return. I say you can get into that period and you start to see a better utilization and it strikes a better balance between the carriers and the producers for a reasonable rate of return on the pipe.

But 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. I hope that's clear.

Got it. And just one last one, if I could. If I'm looking at the guidance increase now versus May, how -- what's the breakdown between fee versus commodity there?

It's a tough -- Al, can you give the numbers? It's -- they're all tied to higher commodity prices, but there's definitely some volume components of it.

Yes. There's one slide that we did a walk for the year -- from the beginning of the year. But 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. And then on the crude oil side, which has actually been a smaller part of the increase, it's driven by the PLA pricing but also this Permian volume growth that we're seeing and is embedded in. So I would say over half of it is more commodity-based and the rest, I would say, would be more fee-based.

One moment for our next question. That will come from the line of Sunil Sibal with Seaport Global.

A couple of questions for me, starting out on your asset sales program, the updated number, $200 million. Is that entirely a function of bringing more assets into the program? Or is it 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. And then I think you folks mentioned about some impact of the outages in Bakken in terms of your NGL assets in Canada. I was kind of curious, have you seen that abate? Or that's something you're kind of still expecting a benefit from the remainder of the year?

Jeremy?

Sunil, this is Jeremy. So as the Williston production went down, gas -- crude oil production, gas production went down. That normally feeds to the Midwest. So more gas was needed from AECO storage. So that was temporal in April and May, but we're still seeing high order flows and high production. Canadian production is approaching 14 Bcf a day. You've got AECO prices hovering between $4 and $5, which is incenting additional drilling. So those are all positive for incremental order flow. So that portion is sustained. But just some portion of April, May, the second quarter outperformance was driven by that. But a substantial portion was driven by better activity in the gas plays within Canada.

One moment for our next question. That will come from the line of Neal Dingmann with Truist.

My first question is on M&A specifically. I was curious as how do you view today's market of existing potential available assets versus I know you've got a lot of room for potential expansion or other, what I consider, sort of organic type buildout. I wonder how you sort of view these 2 things.

Well, we look at a lot of assets that are out there, and we're going to stay very disciplined on it. But the bid-ask spread, I would say, is coming in a bit. Jeremy?

Sure. On the crude side, the market side is deep. It's on the liquids or the gas side, but we're going to remain disciplined, and we'll see opportunities that 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. So we'll be disciplined, we'll look for opportunities. We're constantly engaged in dialogue. But we're only going to do things if they're near-term cash flow accretive and longer-term beneficial for the overall system.

Great to hear. And 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 more for housekeeping. Is that a large percent? Or just trying to get an idea of how much that advantage will be contributed.

To give you a sense, advantage, 50% that we acquired was roughly 30,000 to 35,000 barrels a day, and that will give you a sense from a gross basis what will come back to us. But 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. So I think we had the ability to put additional volumes and eliminate or defer significant capital expenditures. So I think that's part of the allure is to have that idle capacity that we can use to more efficiently operate our system.

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, Sheri. Well, listen, thanks to everyone for joining us today. We look forward to visiting with you going forward, and 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.