Thank you, Dan. Good morning and welcome to Plains All American fourth quarter 2023 earnings call. Today's slide presentation is posted on the Investor Relations website under the News and Events section at plains.com. An audio replay will also be available following today's call. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on Slide 2. An overview of today's call is provided on Slide 3. A condensed consolidating balance sheet for PAGP and other reference materials are in the appendix. Today's call will be hosted by Willie Chiang, our Chairman and CEO; and Al Swanson, Executive Vice President and CFO as well as other members of our management team. With that, I will turn the call over to Willie.

Thanks, Blake. Good morning, everyone, and thank you for joining us. Today, we reported fourth quarter and full year results exceeding expectations in both our Crude Oil and NGL segments. We've made considerable progress towards our long-term strategy while demonstrating continuous execution of our goals and initiatives. In summary, fourth quarter and full year adjusted EBITDA attributable to PAA was $737 million and $2.71 billion respectively, with full year results exceeding the midpoint of our initial guidance by approximately $210 million or 8%. We lowered our long-term leverage ratio target range to 3.25x to 3.75x and we ended 2023 with a leverage ratio of 3.1x. Our efforts to enhance the balance sheet were recognized by the credit rating agencies with two recent upgrades to mid BBB. Additionally, we completed several win-win strategic transactions in both our Crude Oil and NGL segments, including three Permian gathering bolt-on transactions, the sale of our interest in a Canadian fractionation facility, and the recent divestiture of approximately 600 crude oil railcars for proceeds of approximately $40 million. These transactions are representative of our ongoing efforts to optimize our asset base and streamline our operations while generating attractive returns for unitholders. The strong EBITDA results, along with the recent bolt-on transactions and lower leverage, helped to underpin a $0.20 per unit annualized increase in our common unit distribution level, which will be payable later this month and represents a 19% increase in the annualized distribution relative to 2023 levels. Turning to Slide 4, it should come as no surprise that our 2024 key focus areas remain very consistent with last year's. Our strong operational and equity performance over the past year only serves to reaffirm our strategy, most notably our focus on generating meaningful free cash flow, our commitment to capital discipline, and a clear and concise capital allocation framework focused on increasing return of capital to equity holders, while maintaining a strong balance sheet and financial flexibility. As highlighted on Slide 5, we expect adjusted EBITDA attributable to PAA of $2.625 billion to $2.725 billion for 2024. This reflects year-over-year growth in our Crude Oil segment underpinned by continued Permian production and tariff volume growth as well as contributions from recent bolt-on acquisitions. Our guidance also factors in a reduction in our NGL segment, primarily driven by lower forecasted frac spreads year-over-year. As shown on Slide 6, we anticipate 2024 Permian crude oil production growth to be between 200,000 to 300,000 barrels a day exit, with the Delaware Basin driving the majority of the growth. Our updated forecast assumes an average of 300 to 320 horizontal rigs, and as part of our routine fundamentals forecasting process, we will continue monitoring our assumptions as the year progresses. Our Permian JV system is well-positioned with more than 4.4 million long-term dedicated acres and operating leverage to provide customers with Midstream solutions from the wellhead to demand centers. As we show on Slide 7, we expect to capture approximately 275,000 barrels a day of incremental gathering tariff volumes for the full year 2024. For our long-haul systems, we continue to expect high utilization on our Corpus bound assets, a volume step up on basin pipeline, and an MVC step up on Wink-to-Webster. In our NGL segment, we continue to focus on optimizing the business and improving the durability of our earnings. During 2023, we closed the sale of our JV interest in Keyera Fort Sask and we sanctioned a 30,000 barrel per day debottleneck of the Plains Fort Sask complex. The debottleneck project remains on budget and unchanged in the service date of mid-2025. With that, I'll turn the call over to Al.

Thanks, Willie. We reported fourth quarter adjusted EBITDA of $737 million, which includes Crude Oil segment benefits from Canadian market-based opportunities and increased volumes across our systems, primarily in the Permian along with NGL segment benefits from stronger seasonal sales and higher realized frac spreads. For the full year, we reported adjusted EBITDA of $2.71 billion. Strong full year performance is primarily driven by higher realized frac spreads, market-based opportunities, strong base business performance, and contributions from bolt-on acquisitions. Slides 13 and 14 in today's appendix contain walks that provide details on our fourth quarter performance. A summary of our 2024 guidance and key guidance assumptions are on Slide 8. Looking at 2024 compared to 2023 and as illustrated by the EBITDA walk on Slide 9, we expect adjusted EBITDA of $2.625 billion to $2.725 billion with year-over-year growth in our Crude Oil segment, partially offsetting commodity price headwinds in our NGL segment. Growth in our Crude Oil segment is primarily driven by anticipated tariff volume increases, higher fees from tariff escalators, and full year contributions from bolt-on acquisitions. This is partially offset by our assumption of fewer market-based opportunities. We expect lower year-over-year NGL segment adjusted EBITDA, driven by lower forecasted frac spreads, partially offset by higher C3 plus spec product sales in 2024. I would note that our C3 plus spec product sales volumes are approximately 90% hedged for the year at the mid $0.60 per gallon level. We remain disciplined with our capital investments, with approximately $375 million of growth capital and approximately $230 million of maintenance capital expected for the year, net to PAA. This includes capital for POP JV well connections and intra-basin improvements, as well as an increase in our capital related to our previously announced Fort Sask debottleneck project. As illustrated on Slide 10, in addition to capital discipline, we remain committed to significant returns of capital and maintaining financial ability. For 2024, we expect to generate $1.65 billion of adjusted free cash flow, excluding changes in assets and liabilities, with approximately $1.15 billion to be allocated to common and preferred distributions inclusive of the respective increases resulting in $500 million of adjusted free cash flow after distributions available for value-creating opportunities, including potential bolt-on acquisitions or net debt reduction. Regarding our senior note maturity profile, we have $750 million of notes maturing in November 2024, which we would expect to refinance all or a portion of during the year. With that, I'll turn the call back to Willie.

Thanks, Al. Ongoing geopolitical turmoil continues to drive market volatility along with potential impacts to energy and economic policy. Despite this environment, Plains is well positioned today and going forward to continue delivering value to our unitholders. As we show on Slide 11, we've made meaningful progress on our long-term goals and initiatives and continue to position ourselves to be the partner, employer, and investment of choice. In summary, our balance sheet is much stronger, with year-end 2023 leverage at 3.1x. We continue to demonstrate capital discipline and patience as we look at additional opportunities to grow the business organically and inorganically through accretive and synergistic bolt-on acquisitions. Last but not least, we remain focused on increasing return of capital to our unitholders. We believe the world needs North American energy supply long-term and that our business will perform well in both the near-term and longer-term environment. I'll turn the call back over to Blake, who can lead us into Q&A.

Thanks, 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 all participants an opportunity to ask questions in our available time this morning. The IR team will also be available to address any additional questions you may have. With that, Daniel, I'll turn the call over to you.

I wanted to ask a little bit on the ’24 guidance. Your Permian Basin level growth forecast is pretty close to your own gathering volume growth estimate, and I’m just wondering if you could speak to that. Is that a function of your market share in the basin? Is that just a coincidence? And then, the guidance also assumes a pretty nice jump in Western volumes year-over-year. So I wonder if you can talk about what’s driving that as well.

Yes. Michael, this is Willie. The 2.75 maybe for clarity, it is composed of two factors. One, the M&A, the bolt-on transaction volumes that we added last year and that's about 150,000 barrels a day, and then growth from the growing basin, which is about 125,000 barrels a day. And on the Western volumes, Jeremy, do you want to comment on that?

Yes, if you're speaking about Delaware Basin volumes being Western California. That was due to some downtime at the beginning of last year. So, it’s basically just normalizing to the second half of the year runway and some shutdown from California refineries, which pushed more volumes to the pipe. So, it's a combination of those two things.

Okay, perfect. Appreciate all that. And then, just wanted to ask, it seems like the open season on Gray Oak is moving forward, so just wanted to get your views on how you see that impacting your re-contracting efforts on Cactus and then just generally on overall supply versus takeaway out of the basin?

Sure. So what I would say first is the ray of the open season. We expect it to be successful. We're continuing to have constructive dialogue with our customers and see no reason why that's going to impact our re-contracting negotiations. As far as takeaway from the basin, the pipes in Corpus are still full, lift lengths are still full. We have some flex on a few pipelines in the area, but as the basin grows, it will tighten. But it is a constructive market. People know where they want to bring their barrels for the future, and we would continue to be positive on the long-haul pipe as time goes.

Maybe to follow up on Michael's question on just the 300,000 barrels of Delaware growth, which you bifurcated between some organic and or inorganic year-over-year, just given high-level Plains is 50% of the market share in the Permian of which I think you're more highly leveraged at Delaware. Just kind of curious, if you can help us kind of square out kind of that gathering and long-haul guide a little bit more, do you see outside gathering share opportunities in the Delaware just given that more growth is expected to come from there in ‘24?

So, I think Willie outlined the sources of the gathering growth specifically Midland versus Delaware. It’s a function of activity. So if you look at the number of rigs working in the Delaware, it's probably 170 to 180. You have closer to 120 working in Midland. When you offset declines in new production, that’s what yields the growth. You had significant growth in the fourth quarter of last year, so you would imagine it to be slower in the first half, stronger in the second half, which is consistent with some of the public E&Ps that have guided so far this year. So, the Delaware Basin growth is a function of activity. We do have a stronger position in the Delaware Basin, so that impacts us disproportionately. So, I’d say that’s that piece. That’s for the long-haul guide. I think you were referring to the fourth quarter versus the full year long-haul numbers. And what I would say there is, we had outside contribution from the basin in the fourth quarter, a more normalized view for the year next year.

Maybe that's my follow-up switch to capital allocation. Plains enters ‘24 with a similar Tier 1 free cash flow yield in the space similar to ‘23. Last year, we saw debt reduction in some opportunistic M&A along with the distribution bump. So, kind of curious, as we look ahead to ‘24 preferences of that excess cash and specifically on M&A, do you see a similar amount of like bolt-on opportunities in ‘24? Are they more limited at this juncture to where debt reduction might be the preference next?

This is Al. Our focus will be to continue to look at potential to make investments that are accretive to our valuation. We're hopeful that we'll be successful on some bolt-on acquisitions, but we don't know. We feel in the near term, if we aren't successful with that again continuing to reduce debt is not a bad alternative pending that opportunity set. We do not specifically believe that we need to continue to reduce debt. However, our priority will continue to focus on investing, returning more cash through distributions, and looking for other value opportunities around using that cash flow.

Maybe I'll add something to what Al said. When you think about the evolution of where we are, I'm not saying anything people don't know, but it's pretty remarkable where the industry has gone as far as shifting to an export market. A lot of capital has gone into the industry in the last decade. And I think what we're seeing right now is really kind of a change in the business cycle focus on returns, which is really going to reinforce more opportunities for asset sales and consolidation. And really to address your question, I do think there are going to be more opportunities in there and frankly, we just need to be very patient and capture it. Our asset base is well situated to be able to capture synergies across the system in many of the basins we operate, but particularly the Permian. The key now is to stay very disciplined, and at the right valuations, I think we can add bolt-ons just as we did last year.

Could you maybe on Cactus, just give a little more color on where you are at working to re-contract that pipeline timing of when you hope to resolve it and high level goals for that? And I guess just big picture how you’re thinking about a desire to have contracts with medium-term duration versus operating the pipeline on a less contracted basis, depending on where price settles out?

Keith, this is Jeremy. What I would say is, it's constructive for us to have those dialogues now versus where it was the last couple years. We expect to give you guys an update on that this year, but for competitive reasons it doesn't make sense to right now. What I would say is, there's usually a mix and it's largely we have to clear the base and these pipes need to move barrels every day. The owners of the capacity on that pipeline should be someone with ratable export takeaway because that's where it's going. In a lot of respects, it makes sense to contract those pipelines with the third parties that will be exporting the barrels. We serve the function of aggregating barrels from the lease to the market center. We have the liquidity in our terminals. They like to partner with us. It's matching up the supply on one end with their takeaway on the other. It needs to have a strike a good balance of contracting with third parties and some marketing opportunities. But for us, it’s more weighted to contracting and partnering up with the off-takers like the Wink-to-Webster to refiners like our Corpus pipelines as the exporters.

Keith, just to reinforce the point that Jeremy made. Many people we talk to think that our partners could disappear. We've got great partners on this line, folks that are shipping. And so, the way I would couch this is, we've got a great relationship with our partners and the shippers on the line, and this is just a normal course of business that you have to go on renegotiation as far as term and tariff.

Got it. Thanks. Second question just, the Company has had really good market-based results the past two years on Canadian crude spreads and NGL market dynamics. I think in Slide 9, you're assuming fewer market-based opportunities in 2024. Is that a function of their specific areas where you just see less opportunity this year? Or is it just conservatism built-in/kind of a lack of visibility at this point? Just how you would characterize that bucket on market-based opportunities?

Yes. Market-based opportunities, you can't predict them. They are very difficult to figure out when something might happen. Some of this is weather, some of it's other asset rely on, and there's all kinds of things that factor into this. And we've been pretty conscious of not trying to forecast in a large capture for things that we don't know are going to happen. So one of the fundamental changes this year is we have, not we, but the industry has a Trans Mountain that’s starting up that could impact the opportunities for crude market opportunities. We factor all this in. And to answer your question, we don't have a tremendous amount of—we have a modest amount of market opportunities that we have captured that we think we can probably catch. The answer is if there are opportunities out there, it's in our ethos and DNA to capture markets. We've got the broad assets and a company with people that focus on this every day. And so, if there are opportunities out there, we'll capture, but it's very difficult to predict exactly where they happen. And again, this year's budget is based on a modest amount of market opportunities and that's frankly why we moved towards the range to give people kind of a range of thought of what those might be. I hope that helps.

Can you talk through the puts and takes of TMX starting up on Plains' various assets in Canada, your Canada crude pipelines flows to Cushing, et cetera?

Hi, Jean. Good morning. It’s Jeremy. It’s a function of time. It’s not just linear, but at startup you would imagine there’d be less market-based opportunities, but there’ll be the opportunity for more production growth in the basin. It will offset some current flows like rail from the Williston or exports of heavy from the Gulf Coast first. And then you’ll have replacement of—and in our opinion—you’ll have replacement of production growth in Canada. So in that initial period, there’ll be less market-based opportunities, depending upon the flows that go west. If it’s lighter barrels or heavy barrels that could impact flows to the Midwest of basin barrels or other light barrels. So there are opportunities, we're going to have to wait for it to start up and transition into the full capacity that can be reached and what those flows will impact all those components. But we have a flexible system. We're touching all parts of that value chain. So if it’s fee-based growth on the gathering systems, we’re excited about that as the base and titans again, and market opportunities come back, that’s fine for us too, but we'll be there wherever the opportunities present themselves.

Okay. Thank you for that and just a kind of similar follow-up. Some Bakken contracts began to roll this year on HH and DAPL going out of the Bakken. Do you anticipate any major change in how much Bakken crude makes its way kind of the westbound route down to Saddlehorn or the Cushing market or other things that could impact plans as EBITDA?

Sure. There are several factors that have had an impact. Some gathering systems supply the DAPL system while others take from it. Beyond those specific barrels, it will likely be a competitive situation between the groups heading south and those going to the Gulf Coast in Toka. We remain patient and maintain communication with our customers. Saddlehorn is primarily at capacity from the DJ Basin, with some activity from other areas, which are presenting opportunities. We will continue collaborating with shippers to facilitate transportation south if it makes sense, but there will be ample supply in that region.

I wanted to touch on the 90% of NGL fracs spreads that are hedged for ‘24. Obviously, product spreads have trended up lately. I was wondering if you're able to catch some of that with the incremental hedges you put on, and how are you looking at perhaps hedging more than usual and maybe going up to a 100% if you're content with this spread environment right now?

Neel, the first thing is really backwardated. Until natural gas prices tanked a few weeks ago, it was substantially lower. So, this is relatively new, and it is much higher in the front. I think 2025 is $0.56, $0.57 and prompt could be at $0.80. So that backwardation prevents a lot of forward hedging. Our hedges are consistent with what Al said in the mid-60s at roughly 90%. And what you could say is that the hedging profile for us is somewhat consistent with the forward market. So, we're higher hedge than the front and lower hedge than the back end of the year, if that's helpful.

Okay. And then second question, Jeremy. Maybe just if there's a way to kind of bridge where the Midland MEH spread is right now for ‘25 and where you're looking to contract? And how we should look at it on a contract basis versus a spread basis when you're signing up these contracts?

What I would tell you, Neel, is that most of these contracts are for the latter half of ‘25 and forward. So, we’re not really looking at the `25 market; we’re looking more at what is the constructive long-term rate to ship barrels from the Permian to the Gulf Coast. And so that’s between us and the shippers, but we’re having constructive dialogue, and we’re less worried about ‘24 and ‘25 and more about what the long-term rate is after the contracts roll.

I wanted to ask for more details on the 2024 intra-basin and long-haul volumes. It seems the guidance for 2024 is lower compared to the fourth quarter of 2023. Could you explain the factors behind this? Additionally, do the long-haul shipments include the 50,000 barrel per day shipments that have already been prepaid?

I'm going to go back and look for your question here. So you said intra-basin volumes on the guide versus long-haul. So, I'm looking at Q4 of long-haul and intra-basin and then for next year. I would say, there's probably some noise in that Q4 had a bunch of flush production. Some of that volume with Wink-to-Webster connecting in it Wink. Some volume will go in that direction, which is actually a positive because those are shorter-haul tariffs and that leads to integrated movements on our gathering system. So, I’d say this is all consistent with our guidance and constructive for volume growth out to the Delaware Basin. And then the long-haul side, I believe I answered that question earlier; it was just a surge in basin production in the fourth quarter and more normalized for the rest of the year.

And then for the second one, it looks like Plains is approaching the long-term distribution coverage target. So just could you walk through how you guys think about distribution progression from here? Maybe versus a step up and then flattening out or a more rateable moderate step up in the future.

Well, I think our current guidance for this year shows 190% coverage. So, we’ve got a bit to go. Our stated approach will be $0.15 a year until we hit the 160%. And then, DCF growth will drive future increases there. So, we haven’t provided guidance for ‘25 or ‘26 yet. But yes, with this 19% or 20% increase we just did, we’re still at 190% coverage.

So, I just want you to dwell a little bit on your gathering volumes. Could you give us a sense of your gathering volumes in Permian, roughly, what percentage of that comes from your dedicated acreage versus day credit where you may be competing for volumes?

Hi, Sunil. This is Willie. I don't know if you were on earlier, but the overall gathering volume increases are 275,000 barrels a day, 150,000 of it's from bolt-ons that we did. The remainder of the growth, 125,000 is really all Delaware Basin growth.

No, I was actually referring to your current gathering volumes. I was curious in Permian, is there a good sense of what all comes from your dedicated acreages in Permian versus the acreages where you may be competing for those gathering volumes?

Sunil, I would say the vast majority is associated with the 4.4 million acres that Willie referenced in his script. That is dedicated.

Sunil, that's probably something we're not going to comment on, all the what ifs. I can assure you that we look at, we run models on all kinds of different things, we look at all the different assets and opportunities to create value for our unitholders. And on the same token, we look to optimize our own asset base as we've proven over the last number of years. It's a dynamic activity that happens every day. It's really hard to focus on valuations in different basins. We'll have to maybe we can follow up with you offline and see if we can answer your question a little bit better.

Good morning, guys. Thanks for the time. My question maybe Willie for you and Al just on Permian volume expectations, you did a good job. You mentioned the rig count, which continues to be nice and stable. But to me, what seems to get a bit lost is the improved continued D&C efficiencies that have since resulted in more volumes even with these similar levels. I'm just wondering, do you all continue to see this type of upside as I do even if the D&C, if the rigs stay relatively stable? Are you still expecting some nice volume upside on your part?

I think our forecast is consistent with what the industry is doing today, but they're all working to get better. If you look at oil in place targets, they're achieving and first recovery is less than 10%. We're trying to get higher than that. If they do that that would be where a big movement would be, what I would say though is, consistent with our view of supply and demand and current D&C practices. I would agree with you that there’s probably been 10% efficiency of just drilling completion time since the steadying out of the rig count. So, the 300 rigs is probably doing the work of close to 330 rigs 12 months ago. But as far as recoveries, I think recoveries and our view of efficiencies are built into our forecast this year. But longer-term, our bet would be on the U.S. E&Ps that they would figure out how to get higher recoveries.

Neal, remember, we do a top-down assessment. We also have our connection forecast. It’s kind of bottoms-up. And so, we factor all that together and that’s where we got our number from.

Sure. I think that's a function of location. So, the Fort Sask is limited on fractionation capacity, which is why we're expanding in our peers. So, there could be some pressure on wide-grade prices there. I'd say in the Gulf Coast, production growth will continue on the NGL side as associated gas and other gas grows—sources grow, and so there needs to be some expansion of dock capacity and fracs in the Gulf Coast. So you could see some issues there. But in a lot of the locations where we sell our NGLs there, structurally short and inability to bring additional capacity into, so we'll continue to try to sell into those markets and maximize basis.

I wanted to touch again on Permian crude, just on— you commented on your bottoms-up estimates. I'd be curious, if you could give us a bit of a read on what you’re seeing for private versus public activity. And I think also related last year on the call, you just gave a bit of a your sensitivity to changes in basin production from an EBITDA basis maybe just a refresh on that too?

So John, your first question, private versus public, we’re not going to disclose any information from our customers, but generally a lot of the private inventory has been sold into the public hands. So, the privates are now buying back from the independents, lesser-loved assets and starting to redevelop again. But I focus on the public, it has been consolidated to look at their growth forecast and that's largely consistent with our forecast. And as far as the EBITDA refresh, I'm not sure I got that question.

Yes, I guess last year on the call you said maybe like a 100,000 barrel a day swing for the basin would be like a $10 million to $15 million EBITDA impact. Just curious, if that number is still fair for ‘24 or there are some other moving pieces in there to refresh?

Yes sir. That's consistent with the contracting profile we have. So, there's not a lot of turn in the contract, so it doesn't really change much. Well, one thing is I wouldn't consider the Oryx buy-in right? That's our partner in there, we merged those assets together, so I just want to make sure we're clear on that. But second, that the JV has done exactly what we thought it would. And I would say, it is bolstered our relationship with our customers across the basin and given us the opportunity to provide integrated economics. But as for the markets will dictate where barrels flow and pricing dictate where they flow. And so, we have strong relationships and the ability to contract our pipes, but they can only be so full. And so barrels have to flow in other directions as well. And we're completely comfortable with that.

I had a quick follow-up related to Jean’s earlier question on TMX’s impact on your crude marketing business. Completely understanding that the differentials to both Mid-Con and Gulf Coast should be constrained, especially upon landfill, but as TMX delivers barrels to the West Coast backing out some of the Middle East and LatAm imports, and given your liquid infrastructure business there as well as your marketing presence. Is that potentially a source of upside to crude marketing in 2024, relative to opportunities in 2023, as those waterborne imports are backed out and the flows and differentials change in California?

Theresa, this is Willie. It is a complex question that's hard to put a pin to. What I can assure you is that we have a very flexible system and that wherever flows will go, I think we'll be able to adapt to that and capture value perhaps in different parts of our system. Long term, I look at this as very constructive because with more takeaway capacity to the West Coast, I think it allows a better price signal to producers to be able to produce more short term. We could see some headwinds, but I can assure you that we’ll adapt to that. Whatever the markets are we’re going to try to look and see how we can use our assets to capture value.

Quick thanks for all the color on the Permian. Quick question for me, kind of higher-level question on a sector strategic initiative. So, we've seen a ton of M&A activity on the upstream side. Really saw some of these blockbuster transactions. So I have two questions for you on this. Number one, how do you view upstream M&A, specifically kind of for Plains and for the Midstream sector? Is that good for you, bad for you, kind of neutral? And the second follow-up I have to that is, how do you think upstream M&A, this large scale, this large-scale upstream M&A, ultimately trickles sort of Midstream sector? Because we haven't really seen any blockbuster transactions there, right, we've seen one big deal over the last, call it 12 to 18 months that had some call it tax attributes to it? Or is it more so smaller bolt-on and that's the way to go? So, just curious as to what your thoughts are on that.

Well, Timm, the short answer on the question. For upstream consolidation and the impact on Plains with our asset base and the relationships we have, I don't think it's going to be a material impact on us. We work with if not all, most of the large players. So, we've got volumes that flow on our systems today, and they're tied with contracts. And the way I think about it is if you have stronger counterparties in tougher environments, we're fine if they want to develop the Permian in a more thoughtful and efficient way because we're a long-term company and we want to be around for a long time. So whether or not the production comes this year, next year, or the following year, the stability is probably a very positive thing for us. And then, when you think about the Midstream, my observations are, I do think the upstream is a bit ahead of us. I do think there will be some more consolidation. Assets are probably the easiest way to go. And again, as you look at the landscape, there has been some M&A in the Midstream, but I think we are in the part of the business cycle where there are more opportunities to be bigger and be stronger. Not that we aren't a large enterprise, but we'll evaluate different opportunities as we go, always with the unitholder in mind.

Thanks to all of you for your interest in Plains, and we will look forward to updating you as the year progresses. Everyone have a nice weekend. Thank you.

This concludes today's conference call. Thank you for participating. You may now disconnect.