Good day, and thank you for standing by. Welcome to the PAA and PAGP fourth quarter full year 2021 earnings conference call. At this time, all participants are on a listen- only mode. After the speaker's presentation, there'll be a question and answer session. To ask a question during that session, you'll need to press star one on your telephone, and if you require any assistance during the call, please press star zero. I would now like to hand the conference over to your speaker today, Mr. Roy Lamoreaux. Mr. Lamoreaux, the floor is yours. Thank you, Chris. Good afternoon and welcome to Plains All American's fourth quarter and full year 2021 earnings call. Today's slide presentation is posted 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 and non-GAAP financial measures are provided on slide 2. A condensed consolidated 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 session, including Harry Pefanis, our President; Chris Chandler, our 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'll now turn the call over to Willie. Thank you, Roy. Good afternoon, everyone, and I wanna thank you for joining us today. It's really quite remarkable what a difference a year can make. Year-over-year, global crude oil demand is up over 5% and back to near pre-COVID levels, and global oil prices have increased over 50% with WTI and Brent trading near $90 a barrel. The Permian Basin, which is key to our financial success, exceeded our 2021 expectations, exiting the year at roughly 5 million barrels a day with crude oil production growth of approximately 540,000 barrels a day over year-end 2020. We expect the basin to add approximately 600,000 barrels a day annually for the next several years, and our asset base, built over decades, is well-positioned to capture future growth with meaningful operating leverage and modest capital requirements. We also have a significant NGL position in Canada with asset optimization and emerging energy opportunities across our footprint. All of this puts us in a good position to continue improving our financial flexibility and reinforces our confidence in the long-term outlook for our business. This afternoon, we reported fourth quarter and full year 2021 results exceeding our expectations. Additionally, we furnished 2022 full year guidance incorporating Plains' share of the Permian joint venture, and we have revised our reporting segments to create two business segments, one for each of our crude and NGL businesses, which more consistently aligns with how we view and how we operate our business. Our 2022 adjusted EBITDA guidance attributable to Plains is $2.2 billion, which represents approximately $200 million of growth when adjusting for unique items benefiting 2021. Al will discuss these and other details during his portion of the call. As shown on slide 4, 2021 was a year of solid execution for us in a competitive environment. Overall, we executed well and we achieved our goal set out in February to maximize free cash flow, complete our multi-year capital program, further optimize our portfolio and advance our sustainability efforts. We generated approximately $1.65 billion of free cash flow after distributions, exceeding our February forecast by approximately $600 million, primarily driven by asset sales that exceeded our target by $125 million, continued capital discipline with reduced capital expenditures of approximately $230 million versus our initial guidance, and further operating and commercial optimization. We repaid $1 billion of debt, built $450 million of cash on our balance sheet, and we repurchased $175 million of our common equity, bringing our cumulative repurchases to $228 million since November 2020. We also completed our multi-year capital program with both the Capline Reversal and Wink to Webster projects now in service. We are also well on our way to integrating our Permian assets with the Oryx system, and we are confident that the JV will generate at least $50 million in consolidated run rate synergies in 2022. In addition, we also made meaningful progress in our sustainability efforts, including establishing a new health, safety, environmental, and sustainability board committee for providing additional oversight and perspectives. In regards to our emissions profile, we have further increased disclosure around our Scope 1 and Scope 2 emissions, which reflect ongoing reductions over the past three years and absolute emissions at the lower end of our peer group. We expect to continue the improvement trajectory through the efforts of our newly established emerging energy team, which is focused on a number of capital efficient opportunities to further optimize our existing assets and lower our emissions. Operational excellence continues to be a primary focus in our sustainability efforts, and we strive to continue to raise the bar, and we've made tremendous progress in our key health, safety, and environmental metrics over the past five years. We've reduced federally reportable releases and total recordable injury rate by approximately 40% and 50% respectively. Although we missed our 20% reduction targets in 2021. The severity of incidents we had were down greater by 25% and lost time days were down more than 90%. I'm confident in our ability to continue improving going forward. With regards to capital allocation, our goals and initiatives remain centered on maximizing free cash flow and allocating it through a balanced approach, continuing to focus on debt reduction in the near term while increasing cash return to our equity holders over time. Based on the progress we've made to date and our expectation of generating meaningful cash flow over the next number of years, we intend to recommend to our board an increase in our annualized distribution of $0.15 per common unit. Which, based on our guidance, maintains the capacity for continued discretionary repurchase activity. Our expected 2022 coverage ratio, taking into account the distribution rate that we plan to recommend to our board, is approximately 250%. This leaves room for responsibly returning additional capital to equity holders over time. Al will share additional detail on our financial strategy and our capital allocation priorities later in the call. Now let me share some comments on industry fundamentals that are shown on slide 5. As I briefly mentioned earlier, global crude oil demand is near pre-COVID levels, with the EIA and other third parties forecasting demand growth of approximately 3 million-4 million barrels a day in 2022, and continued growth for the foreseeable future. We expect this demand growth, combined with the multiyear backdrop of reduced upstream investment and a continuation of OPEC discipline, will exacerbate many of the market concerns already being experienced today. This includes tight global markets and continued commodity price volatility. As a result, over the longer term, we expect that North American energy supply will continue to play a key role in meeting global demand growth, and the Permian is positioned to drive a vast majority of U.S. production growth. It's against this macro backdrop that we expect to generate significant cash flow on a multi-year basis, supported by our integrated business model from producing regions to key market and export hubs. We have a very flexible asset footprint with operating leverage, particularly in the Permian, and modest capital investment needs for a number of years to come. With that, I'll turn the call over to Al. Thanks, Willie. To open my portion of the call, I will share a few comments on our new crude oil and NGL reporting segments, as well as the treatment of non-controlling interests within our reporting. Our new segments are reflective of how we view and run our integrated crude oil and NGL systems, aggregating supply from producers, delivering to end market demand, and all the steps in between. We believe the new segments will provide better visibility and transparency into the drivers of our overall business and reduce inter-segment activity. Additional information regarding the new segments will be disclosed in our 2021 10-K filing. As a reference tool, we have included a number of segment-specific materials within the appendix of today's presentation, including historical, financial, and operating information by quarter. As a reminder, our NGL segment typically generates seasonally stronger results during the winter months. In regards to our Red River and Permian Basin JVs, both of which are consolidated into our financials, we are reporting adjusted EBITDA attributable to PAA, which excludes EBITDA attributable to the non-controlling interest as our segment measure for both historical and forward-looking numbers. We will also use this measure in calculating our leverage ratios as both consolidated entities are debt-free. The adjusted EBITDA attributable to the non-controlling interest in our Red River JV is $17 million for 2021. Accordingly, our full year 2021 adjusted EBITDA guidance of $2.175 billion provided in November corresponds to an adjusted EBITDA attributable to PAA of $2.158 billion, and this compares to our 2021 actual results of $2.196 billion. Moving to the quarter, an overview of our fourth quarter results is illustrated on slide 6. Fourth quarter segment adjusted EBITDA of $564 million was driven by better-than-expected performance of our Canadian crude and NGL businesses, as well as stronger volume throughput across our Permian pipeline systems. A summary of our full year 2021 results and 2022 financial and operating guidance is included in slides 7 and 8. We've modified our guidance approach by providing annual guidance only, guiding on our expected year-end leverage ratio, and including these within our quarterly earnings slides. For 2022, we expect to generate full-year adjusted EBITDA of $2.2 billion, $2.1 billion of cash flow from operations, and $1.4 billion of free cash flow, and we expect to exit the year with a leverage ratio of ±4.25x, which is further explained on the slides. I would also note that our cash flow from operations and free cash flow guidance incorporate reasonable assumptions for short-term working capital needs and do not factor in material unforeseen impacts. We expect approximately $100 million of asset sales in 2022, including $50 million deferred from 2021, which closed in January. Now let me put our 2022 adjusted EBITDA guidance in perspective versus 2021 results as illustrated by the EBITDA walk on slide 9. 2021 results included certain unique items totaling approximately $200 million in the aggregate. These items consist of net margin activities, including crude oil contango profits from positions established in 2020, partially offset by improved NGL margins. 2021 also included the benefit of seven months of earnings from our gas storage assets and one-time items related to Winter Storm Uri. The unique items are expected to be largely offset by approximately $200 million of growth, including the benefits of Permian volume growth expectations, Permian JV synergies, and recent project completions. Furthermore, we expect 2022 to benefit from resumed activities at our Fort Sask facility and tariff escalation, which we forecast to be a modest uplift after offsetting inflationary impacts. Moving on, slides 10 and 11 provide the overviews of our financial strategy, capital allocation priorities, and current financial profile. We remain focused on maximizing free cash flow and allocating it through a balanced approach that reflects a continued focus on debt reduction in the near term while increasing cash return to our equity holders over time. As a result of our progress to date and our continued prioritization of debt reduction near term, Moody's upgraded Plains to investment grade in November. As shown on slide 11, we established a new leverage ratio which closely aligns with the rating agency's leverage calculation, and we are targeting a range of 3.75x-4.25x. Our leverage is currently above the high end of the range, which reinforces our commitment to further reduce debt. We believe the new ratio and disclosing our expected year-end 2022 leverage as part of the guidance process will provide greater clarity into our capital allocation decisions. Slide 12 summarizes our capital program. With the completion of our multiyear build-out, we remain focused, disciplined and focused on must-do, no-regrets capital. Net to Plains, we expect 2022 investment capital of ±$275 million and maintenance capital of ±$210 million, inclusive of a $35 million NGL facility turnaround. Going forward, we expect annual run rate investment and maintenance capital of $250 million-$350 million and less than $200 million, respectively. This includes approximately $50 million of capital related to non-controlling interests. Slide 13 shows our sources and uses of cash in 2021, our current guidance for 2022, and our directional expectations for capital allocation in 2023 and beyond. Including asset sales in 2021, we generated roughly $1.65 billion in free cash flow after distributions, allocating nearly 90% to debt reduction and the balance of $175 million to common equity repurchases. The debt reduction allocation includes $450 million in cash on the balance sheet at year-end, the majority of which will be applied towards the early retirement of $750 million of senior notes on March 1, 2022. In 2022, we expect to settle into a more normalized cash flow profile driven by business performance and capital discipline versus asset sales. We forecast free cash flow after current distributions at ±$700 million, and we intend to continue to focus on achieving our targeted leverage ratio by allocating approximately 75% to debt reduction, with the remaining 25% funding the contemplated distribution increase as well as discretionary repurchase activity. As we expect to reach the top end of our leverage range by year-end 2022, we believe we are well positioned in 2023 and beyond to further increase the percentage of free cash flow allocated to equity holders while reducing the percentage allocated to debt reduction. With that, I will turn the call back over to Willie. Thanks, Al. Well, 2021 was a positive year for our business, generating significant free cash flow, allowing us to reduce absolute debt levels and return cash to our equity holders. Looking ahead, we are well positioned to drive multiyear free cash flow generation and unit holder returns. There are four primary levers to increase our cash flow as they are reflected on slide 14, and they include, first, the operating leverage of our core Permian business, supported by improving global fundamentals. Second, our integrated NGL operations and the opportunities around those assets. Three, a continued optimization of our existing assets, including renewable opportunities. And last but not least, our improving financial profile. Overall, we like our positioning, and we are very optimistic about the future. As we discussed throughout the call, 2021 was a strong year of execution. In that regard, I would like to acknowledge our entire Plains team for their dedication, perseverance, and patience through an uncertain and challenging 2021, and I wanna thank them for their ongoing contributions to the partnership. A summary of our 2022 goals and key takeaways from today's call are provided on the slides 15 and 16. With that, I'll turn the call 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, and 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 afternoon. Additionally, our investor relations team plans to be available throughout the week to address additional questions. Chris, we're now ready to open the call for questions. Thank you. To ask a question, please press star one on your telephone. To withdraw your question, please press the pound key. Stand by as we compile the Q and A roster. Our first question comes from Keith Stanley of Wolfe Research. Your line is open. Hi. Thank you. Maybe I could start with the dividend and the 20% increase. From here, I'm assuming you're thinking annual assessment of the dividend. I guess once balance sheet objectives are fully achieved and not just the top end, how do you think about the payout ratio as a percent of free cash flow? It's still a little low versus peers. Is there any guidepost you would use to size the ultimate dividend once you hit your balance sheet targets? Yeah. Thanks, Keith. Let me start by saying we've had an annual dividend policy review, distribution policy review ongoing for a number of years. This is not a change from that, and we're gonna continue that going forward. The way I would look at our allocation, it's probably a little bit of a shift. We've talked about free cash flow after distribution, and we've articulated a wedge, and I call it the capital allocation wedge, where we're taking 75% of it to debt this year and targeting 25% into the unitholder in the forms of a distribution increase as well as discretionary purchases. As we go forward, obviously, that free cash flow we think is gonna stay for a number of years. As debt comes down into 2023, the allocation will increase back to unitholders. What we'll do is, as we go forward, we'll start allocating against a percentage of free cash flow, cash flow from operations as kind of a metric going forward. Al, do you wanna add anything to that? Does that help, Keith? That helps. Thank you. Separate question. Just looking at the waterfall on slide 9, and you know the Permian bucket, you have a number of positive drivers there that are helping. The one thing, just some of the commentary on volume growth in the system, I think it's on slide 8, actually. It talks about 350,000 a day of sort of core year-over-year volume growth as some of the volumes shift to Wink to Webster. Are your-- I guess my question is, are your margins on your existing long-haul pipelines stepping down at all in 2022, or are you just flagging that volume shift over to Wink to Webster, but you know you're kind of already at MVC levels, so there's no real hit to EBITDA, if that makes sense? Well, Keith, I've got two comments on that. One, we highlighted there is a significant shift with a new pipeline coming on. Wink to Webster clearly takes volumes that used to go on our assets and puts it into what I would call durable volumes that have the ability to ramp up. That's a change between 2021 and 2022. As far as the competitive environment, I mean, the way I would characterize it is we're in a very competitive environment, right? With the reset of production resulting from COVID, the long-haul lines, there's been a lot of surplus capacity in that. Over these last few years, it has been a very competitive environment. We expect that to continue over the next few years until production starts balancing with capacity. Okay. I guess I thought you were already kind of running at MVC levels in 2021 on those long-haul pipes. Should we think of that shift to Wink to Webster as having a headwind on the company in 2022, or is it more a volume issue as it relates to headwind? Well, one comment. A good example of that would be the Basin Pipeline, which does not have MVCs. In 2021, we were able to capture volumes going up to Cushing on that. Going into 2022, we expect more of those volumes to go to Wink to Webster. Jeremy, do you wanna add anything to that? Hey, Keith. This is Jeremy Goebel. A few things. One, you're correct, we're at MVC levels, but it's not just Plains assets that'll. It's some of the MVCs to Houston won't get filled as well. I think it's a mix of pipelines across the industry, because there's only a fixed amount of demand in Houston, so you could see that disproportionately impacted as well. I think of Basin as balancing the Midcontinent. When inventories get low in Cushing like they are now, you're gonna start seeing a pullback on the Basin system. There's gonna be ratable demand to Cushing that's gonna ebb and flow as you saw through the quarters last year. As Permian Basin fills and Midland starts to weaken, you would see that more ratable. Think of that as somewhat cyclical throughout the year. I think that Midcontinent demand will largely be driven by refining runs in that area. As far as your question on the Gulf pipelines to the Gulf Coast, largely protected by MVCs, but the spot capacity will represent what the market is. The only part that I would say is there's two parts to that. One is Basin, some of the opportunistic may go away, but there'll be a portion there. The Wink to Webster will be at T&Ds levels. Cactus II and Cactus I, those T&Ds will be in place. That marginal spot capacity as Midland and MEH has come in. That part will be at different tariffs, those incentive tariffs. That will be one headwind and then maybe a portion on volume. By and large, we'll compete for barrels across the system and look to fill them as we always have. That's helpful. Thank you. Thank you. Our next question comes from Michael Blum of Wells Fargo. Your line is open. Thanks. Good evening, everyone. First question, I wanted to just ask about operating leverage. Basically, how much operating leverage do you have in the Permian as volumes ramp, let's say that 600 a year that you're projecting, I guess. Put another way, how does that 600 a year of growth translate into annual EBITDA growth for PAA? Jeremy? Thanks for the question, Michael. It's a little bit more nuanced than that. The first 600,000—think of the next 18-24 months on a long-haul basis, that's going to fill MVCs and the ramps on Wink to Webster and others. There's leverage on the gathering system, which is somewhat market share at the existing tariffs that we have because it's largely dedicated barrels. There's that one-touch barrel plus anything we can do on the marketing side with quality segregations, pump overs, that type of business. There's a throughput component, and then there's the tariff component. As we get to leverage, let's say it's another two years of growth consistent with last year, then you start to get leverage on increasing spreads to the Gulf Coast into markets outside. There's also volume component to that spot volume. It's not linear. It's gonna have a certain impact this year or next year, which we view to be competitive markets. It gets materially higher as you go through this volume, this tariff, and it's not single touch, it's multiple touch barrels. Hopefully that's helpful. It is. Thank you. Second question on the NGL segment. Just want to confirm or clarify that the earnings coming from this segment are basically coming from the Canadian assets entirely. Wanted to ask in terms of the guidance, what's driving the year-over-year improvement in the NGL segment? I think the EBITDA is up, like, 33% per the guidance. Thanks. Michael, there's a couple things. It's primarily Canada. We do have some terminals, and we've got some facilities in the lower 48, but it's primarily Canada. You're correct there. As you think about the difference between last year and this year, a big piece of that is the frac spread environment. Part of the reasons we've resegmented is I think it'll allow people to see the two segments a little more with a little more transparency as we talk about the business. It's certainly how we think about it. Probably the biggest driver is a difference in the frac spread environment between last year and this year. Thank you. Appreciate it. Thank you. Next, we have Jean Ann Salisbury of Bernstein. Your line is open. Hi. Do you see the potential looming lack of Permian gas takeaway as a threat for Plains' growth post kind of 2023, 2024 if E&Ps don't wanna flare this time around? Well, I can tell you, Jean, definitely if there's people are not gonna flare, so there's gonna be pressure on gas takeaway. We don't operate long-haul gas lines in the Permian. If you hear others that are talking about that alliance kind of with your two or three years, 2024-ish timeframe, at that point, I think there's gonna have to be a solution. We've heard about some people with a new build option, and then obviously there's been a number of discussions on is there ability to repurpose a line. As we've shared before, it's a difficult conversation to have because you've got a number of parties, you've got commercial contracts that's complex. I think it's something that we're gonna have to continue to watch as we go forward. There will be a constraint at some point in time. Okay. Jean, just a follow-on to that. I think once again, from a long-haul standpoint, there's a number of players that have firm capacity. Their growth is largely protected. To the extent the production's coming from those, it's the undedicated component that will have more restrictions. When you think of customer mix and who's growing now versus then, aligning with larger customers allows those barrels to flow. I think we've considered that in our growth expectations. I think gas takeaway being one. I think there's some supply chain concerns. We're actively talking to our customers from a regulatory standpoint on the water side. I think we do consider those when we go through our production forecast and talk to our customers. Those issues are actively being managed, but we do pay attention and monitor that. I'd say on the gas takeaway side, the half of BCF today that's out there with the Whistler project that should help and maybe extend that a couple quarters or so. You're right, the flaring is something that could cause intermittent disruptions in the field. We've seen it in the last six months causing intermittent disruptions in the field. They will not flare if there's a problem at a processing plant. The industry is in a good way. That's from an ESG perspective, people going to lower carbon. That's one way we're seeing very actively managed on the producer side. We do take that into consideration in our forecast and we're cautiously optimistic the industry will come to a solution. Great. Thank you. Relatedly, you all have talked about it quite a bit before, but just wanted to make sure that your latest view is that Plains is sort of one of the less likely to convert a crude pipe to gas, just given what your footprint is than perhaps some others. Pipelines in the basin might be. Jean, this is Jeremy. You know, you're gonna need a thicker wall thickness and a higher diameter pipeline than the ones we have going to market. I think it would be unlikely for us to convert something to a gas line. Okay, great. That's all for me. Thanks. Thanks, Jean Ann. Thank you. Next, we have Jeremy Tonet of JP Morgan. Your line is open. Hi, good afternoon. Hi, Jeremy. Hi. I just wanted to dive into the guidance a little bit more with EBITDA. If I look at just Q4 here, and I know there's a little bit of seasonality in Q4, but if I annualize the Q4 2021 number, that comes up above the 2022 guide. I'm just wondering, does the 2022 guide really have nothing on the NGL side, or does re-segmenting impact it? Or is it really the line fill from Wink to Webster really offsets all the Permian growth. Just trying to wrap my head around better how 2022 guide is lower than Q4. Yeah, Jeremy, there's a lot of volumes that shift in Q4, as we earlier talked about, into the Wink to Webster line. So it's not a clean match to do a run rate on Q4. Jeremy, you got anything else to add? Yeah, just Jeremy, as you think about it from a modeling standpoint, the seasonality in the business, the NGL business, I think it's in the appendix, shows the NGL business generating $140 million of EBITDA. If you deduct that from the total and annualize that on a crude basis, that's give or take a $425 million a quarter run rate. What we have forecasted for crude this year is close to $455 million run rate. There was just some timing of some sales in the NGL side and settlement of some MVCs. By and large, the crude segment is growing on a run rate basis, $140 million or $130 million over the year, and the NGL business is going to more normalized quarters. That's a good point on the seasonality of the NGL. Definitely has an impact. Got it. Thanks for that. As far as capital allocation is concerned, you provided a lot of thoughts today, but just wondering if I could dive in a little bit more. It seems like the CapEx this upcoming year, 2022, is a little bit higher than your run rate, and I'm guessing that's just associated with the synergies with Oryx or initial projects there, and that's the key driver there, and it'll come down in future years. Then I guess buybacks versus dividend, we were kind of thinking that the buybacks might be tilted a little bit more than a 21% dividend increase as Plains trades at one of the lowest valuations in the space. So even really just buybacks versus dividend growth, if you could help us with the, you know, how you view that going forward. Al, why don't you take a shot at this? Yeah. Yeah, sure. We look at the way we all allocate capital back to equity holders is a balance between the two, between distributions and repurchase activity. As an MLP, you know, I think the primary approach for returning capital to our shareholders would be through distributions. We think we can balance and accomplish both, so to speak. I think the capital is pretty much in line. I think this year we're showing a quote consolidated investment capital of about $330 million net, $275. It's right on top of, I think, where we kind of expect to be. That consolidated number is up because of the added JV. You know, we show a net number on our guidance slide on page 7, but that's pretty close to where we expect them to run. Maintenance capital is the one this year that's a little higher due to the one turnaround that's more of a 10-year type of turnaround on one of the big units up in Canada. Prospectively, we'll be more talking CapEx on a gross or consolidated basis. Yeah. Jeremy, let me just add to that a little bit. You know, I think everything Al said is right. I just wanted to reinforce, we've got a lot of free cash flow going forward. What I would take away from the recommendation of the $0.15 annualized is really the conviction that we have in our cash flow stream going forward. To Al's point, it's. We don't see it as one or the other. We think we can do both. We've proven that we can buy back shares as we demonstrated over the last year plus. This was a signal really to say, we've got plenty of capacity as far as coverage. It was a nice step-up recommendation that we'll make to the board on distribution and still leaves us enough capital to be able to buy back some shares at the appropriate time. Got it. I'll leave it there. Thank you. Thanks, Jeremy. Thank you. Next we have Tristan Richardson of Truist Securities. Your line is open. Hey, good evening, guys. Appreciate all the comments on the new segments. I know it's not a perfect metric, but you guys used to talk about guidance and express a metric as sort of an EBITDA, you know, per transport barrel. But if I just look at 22 crude segment volume guidance against the crude segment, EBITDA suggests sort of that EBITDA per barrel somewhat less than maybe what you guys have talked about under the previous segments. Should we just think about this as sort of an 8/8ths volumes versus a net EBITDA PAA comparison or, but, you know, we also would have thought there would have been some marketing activity in that EBITDA number. Could you maybe just talk about that a little bit just in the context of how you guys used to talk about EBITDA per barrel? Yeah, this is Al. I'll take a shot. Yeah, as we collapsed all of the crude business into one segment, and we had been reporting crude activity under three, as we looked at it, we didn't believe that we should necessarily try to choose one or two quote volume metrics to calculate the per unit because ultimately, there are variations to it. What we did historically wasn't perfect either. Over time, we had changed volumes when we thought one was more of a driver or less of a driver, et cetera. Clearly today, what we showed in the volumes is pipelines, the commercial capacity that we use and lease out, as well as our lease purchase activity. You know, it's hard to say that all those barrels are necessarily equal as how they drive them across our cash flow stream, and that's why we chose to not actually do the calculation for it. Again, it's the pipelines are probably the bigger driver, but the lease volumes that we purchase and move through our assets effectively are kind of double-counted. Anyway, we recognize it's not perfect, but that's why we chose not to, 'cause as we put it all together, we didn't think there was one way to do it that was really reflective of the way to show it. Similarly on the NGL side. Appreciate it. Thanks, Al. Then I guess just, you know, you talked about kind of priorities for CapEx and maintenance CapEx, really being connectivity focused. You also talked about asset optimization, whether that be brownfield expansions, and JVs. Could you give us a sense of maybe, you know, examples of what that might look like or, potential projects on the horizon that would kind of fit under that optimization category? Chris, you want to take this? Sure, yeah. Tristan, it's Chris Chandler. We're looking at a number of opportunities around optimization. Some of the ones that are maybe further along than others are around our Canadian assets and our fractionating facilities. It looks like we have some low-cost expansions available there that would enable additional throughput and additional NGL production and/or fee-based service up there. Along the ESG lines, we fundamentally believe that energy efficiency at the end of the day is also a good business. We're looking at opportunities to reduce energy consumption and increase energy efficiency at some of our assets that are large energy consumers. We see some opportunities there as well that we'll look to fund if they meet our return thresholds. Hey, Tristan, just to add to it, you know, when you think about our NGL business, we've got large complexes that are straddle plants, fractionation facilities. What we've been doing over the last few years is if you think about our Empress facility, just as an example, there's Empress 1 through 6, and the way that system, that facility has been set up is we've had multiple owners, joint venture partners. What we're doing now is you'll recall we swapped our Milk River asset for proportions of that. By being able to clean up, if you will, the ownership structure, both the commercial side and operating side, there's a number of optimization opportunities to run the six Empress one through six more of a system versus being constrained with each one with different owners. That's something we've been working on for some time, and that offers us the ability to be able to optimize that whole complex. That's probably another very good example of what we're trying to do. Appreciate it. Willie, Chris, thank you, guys. Thanks, Tristan. Thank you. Next, we have Becca Followill of U.S. Capital Advisors. Your line is open. Hi, guys. Thanks for taking my call. I think you talked about earlier about $150 million of synergies from Oryx, if I'm correct, that you expect to realize in 2022. Where specifically should we look for those synergies to occur in terms of line items? Becca, we never quoted 150 in 2022. It was $50 million in 2022, 8/8ths, growing to $100 million longer term. Those are both 8/8ths number. Jeremy, do you wanna articulate where you might see some of the synergy numbers? Sure. Becca, I think it's all of the above. I'd say roughly half of that is probably gonna be in lower CapEx. It'll create. We had capital in our standalone plan to capture some opportunities which would require capital. Having the Oryx system merged with the Plains system eliminates that. Having the ability to connect dedications from one system to the other to shorten laterals is part of that. Let's call that half of the capital savings in spite of inflation, able to reduce that $50 billion by roughly half. Operating side is probably, I'd say 60% of the remaining number, and 40% is just on the commercial side optimizations that we're able to do between the two systems. Our goal is obviously to beat that, but that's what we hang our hat on today and feel like we can capture some of its costs, some of its capital. Commercial, we think we'll step into more as we get to know the system. We've had it for three months. Over time, leases go away, operating agreements with others go away. There's more commercial opportunities across the system, more options to offer customers, more throughput that will all grow with the system. We're excited about it. As Willie said in the beginning, we're comfortable with the $50 million, and we'll look to grow from there. Thank you. Just following up on Michael Blum's question on the NGL segment guidance. You talked about a big piece of the frac spread environment. Can you talk specifically about what has changed in the frac spread environment? Jeremy, you wanna take that? Sure. Think of the frac spread exposure being buying AECO gas and selling TET minus the nickel Mont Belvieu type basis on the NGL side, and it's C3 +. It's cost reimbursement for ethane is basic structure to think about. As you think of the run in liquids prices relative to natural gas, the frac spread has increased materially. Some of the hedges put on last year were done earlier in the year or in late 2020. That step change from an overall frac spread in the $0.50s to north of $0.70 is what you're thinking about. $0.15+ in frac spread across the whole program is largely driving that exposure. There's also a portion of volume. The colder weather in the Northeast is driving incremental demand through our straddle plants, which is increasing volume. It's some volume, some margin, but by and large, it's the commodity exposure in that portion of the business. Great. Thank you. Thanks, Becca. Thank you. Next, we have Michael Lapides of GS. Your line is open. Hey, guys. Thank you for taking my question. I actually have a couple of them. Just I wanna sanity check one thing. I'm looking at the fourth quarter volumes in the Permian at about 5.2 million-5.3 million barrels a day. So your guidance for 2022 basically assumes that you're gonna be flat relative to the fourth quarter actuals. Am I thinking about that right? This is Jeremy Goebel. Yes, part of that is a reduction in longer haul volumes, but it's a little bit more nuanced than that. Volumes that go on Wink to Webster, 16% type volumes. Volumes that went on our legacy systems are 88%-100%. Total gross volumes are up, but net to our interest, they're down. You've seen any reduction there, you're seeing offset by increased growth on the gathering system. As we said before, this is consistent with what we'd expect to see in 2022 and potentially part of 2023 at the growth projections we have. Then you can see that amplify as more volumes on. It's not a one for one on volume growth. As MVCs get full on pipelines, you start to see a multiplier effect on gathered volumes. Understood. The benefit of it should compound over time. The other question I had, I'm just curious. You know, when we think about both Wink to Webster and Capline, how long should we think about the timeline is for each of those to ramp up into kind of a normalized EBITDA run rate? Like, can you remind us, is there a staggering of when the contracts go into effect and when's kind of that year where they're all in effect or they all start to be fully in effect for both lines? Sure. Wink to Webster, think of it as a significant portion of the volume kicked in in February, T&Ds. Think about over the next two years, ratable increases from there to get to full. Maybe two years from now, you'll largely be fully ramped up in MVCs. As for Capline, it started at where we had the MVC levels, but we're actively marketing additional capacity. We have roughly 100,000 barrels a day of additional capacity to offer with no capital, and we're in active discussions with shippers, and we'll update you at the appropriate time. Got it. Okay. Thank you. Much appreciated, guys. Thanks, Michael. Thank you. Next, we have Chase Mulvehill of Bank of America. Your line is open. Yeah. Hey, thanks for squeezing me in here. A couple of kind of questions. I mean, some of this has been discussed, but just wanna dig a little bit deeper. Could you talk about, you know, what Permian oil production levels you would need to see before you really see a pickup in volumes to Corpus, which is basically Cactus for you. You know, the follow-up is, with the same question, you know, what does Permian oil production volumes need to get to see kind of a pickup in Cushing volumes? Chase, I'll start. I do want Jeremy to talk about this 'cause he lives this 24/7. When you think about our system, we get a lot of questions on why barrels aren't flowing one way versus the other. The thing I would reinforce is we've got a flexible system that allows barrels to go where markets are. So I view that as a positive, even though we may be taking some volumes off of a certain system to go to Cushing instead of the Gulf Coast. We think that's a benefit. There's a unique situation going on right now with spare capacity and spot tariffs and MVCs in production. Jeremy, would you kind of share your thoughts on that? Sure. The way I think about it simply is that this year's production growth will go to fill the incremental MVCs on Wink to Webster plus a little bit. Next year's production growth will fill Wink to Webster plus any shorts in the market today. You basically get back to an environment where people are not remarketing space within the next two years based on what I'd say industry standard production growth is. At that point, pipeline tariffs, you start to ship at incremental spot tariffs first, shipping somewhat at discounted level just to fill space. That probably answers all of your questions, but that's just the way we're looking at the market. It's gonna be a competitive market for the next 18-24 months at current production forecasts. At that point, you've filled all existing MVCs. You have spot barrels, which changes the dynamic. Then also, when you think about that, if Midland is short, it starts to price at a premium, and it makes it difficult to go to other locations. As production grows and you get to the point where you're filling MVCs, now that marginal barrel sets the spot price. It makes all markets competitive for the incremental barrel. Midland weakens relative to the other markets. Cushing becomes more competitive, all markets. It is a dynamic market. It doesn't sit still, but hopefully that gives you enough to run with. I mean, if I kind of connect the dots on what you said and what you said earlier in the call, I think you said 600 kind of exit to exit and similar growth next year in the Permian. You know, basically what I'm hearing is you got about 1.2 million barrels a day of Permian oil production growth before you really start seeing some kind of significant operating leverage across the long-haul pipes. Is that kind of a fair assumption? I think at this point it is, but remember that's dynamic because as Oh, yeah. other pipelines, then that number gets smaller. It doesn't have to stay that way forever, right? It's just as MVCs roll off on other pipelines, we control substantial barrels and fill space, so it's dynamic. In this 30 seconds, yes, that would be our assumption. Okay. Great. That's all I had. I'll turn it back over. Thanks. Thanks, Chase. Thank you. Next we have Brian Reynolds of UBS. Your line is open. Hi. Good evening everyone. Start off on capital allocation as a follow-up to some of the previous questions. You talked about a balance between buybacks and distribution raise. Just given, you know, the previous benchmark of 25% of free cash flow going towards return of capital, it seems like that's roughly a 50/50 split between, you know, distributions and potentially buybacks. Is that a fair way to think about, you know, buybacks this year around that $90 million mark? Just kind of curious as we go forward and reduce that further, just wondering if more free cash flow could go towards, you know, distributions or, you know, buybacks, beyond 2022. Thanks. Yeah. Brian, I think your math is pretty close. You know, if I take you back to the slide that we showed this on the 13, you know, again, the free cash flow after distributions, this would reflect before any increase this year. There's two points. One, the point you made, which is the allocation of the 25% to the equity holders, which as we get, as leverage comes down, it will shift and increase. But the real point I want you to take away from this is we've got significant free cash flow going forward. If you think about this blue and what's circled in the yellow, our goal is to get our leverage down. Once that happens, it gives a significant amount of capacity to return to unit holders. That's the point we really want you to take away. Great. That's helpful. As a follow-up on some of the previous Permian guidance questions as well, just wanna clarify. It seems like, you know, 2022 is, you know, filling Wink to Webster, MVCs, et cetera. While on 2023, is that where we could see volumes, you know, moving above MVCs on the legacy Plains pipes and start seeing that, you know, material earnings uplift? Thanks. Yeah. I think it's very consistent with the last question. That's the starting point. We're gonna look to continue to attract incremental spot barrels, but we're not gonna overpay because you're market limited at this point. The Midland MEH spreads $0.20-$0.30. There's no sense in if we can get a $0.10 premium selling at Midland versus consuming $0.15 of power and taking the risk of marketing barrels, it's better to sell it at Midland. You're market limited today, and it's saying keep the barrels in the basin. As that changes, we'll opportunistically move. As Cushing inventories fall, we're opportunistically gonna move barrels to Cushing. To your point on the balances, there are some limitations on that. Sometime in the, as I said, 18-24 months from now or from the beginning of this year, you end up in a period where we think that starts to rebalance. Great. Appreciate the color. Have a great evening, everyone. Thanks, Brian. Hey, Chris, I think we have time for one more set of analyst questions. We'll take this next set of questions and then call the call. Yes. Thank you. All right, our last question comes from Timm Schneider of Citi. Your line is open. Hey. Thank you. Real quick, if I back it to the $150 million or so of well connects for 2022, how should we think about the cycle time of that CapEx? Meaning could some of that show up in EBITDA in 2022, or is that longer dated? Jeremy? I would think of that as a continuous program, and that's a gross number, $150 million. Think of that as $100 million net to Plains. Returns on that, it's gonna be like declines in wells. It's gonna be continuous. Every month, we're connecting a ratable amount, largely. You think that cycle is largely continuous. The cycle of the projects, whether it's four to six months, realistically, we have that as a continuous program. Every month, 4-6-month projects are finishing. Don't view that as a large pipeline where it starts and 18 months later you need capital. That is a continuous piece of capital that's maintaining cash flow and generating substantial returns associated with on a standalone basis. Okay. Got it. Then, just shifting gears to or back to Oryx. You said capital synergy is $50 million going to $100 million, but what's the actual EBITDA contribution that you're forecasting net of Plains of Oryx in 2022? Sure. That's an 8/8ths number. If you take 65% of that, and then like I said, the contribution in 2022 is half capital, half EBITDA generating concepts. Think about it, net to Plains is 65% of the $50 million, and half of that would be EBITDA. Half of that would be reduced capital. The total 65% would go to free cash flow, which is largely how we're looking at our business. Okay. Got it. Sorry, go ahead. Go ahead. I was just saying. I was gonna say- Anything that reduces sustaining capital to us is free cash flow generating, so that's how we're looking at the business. Okay. Understood. The 600,000 barrel a day increase, is that just to clarify, is that an exit-to-exit number? It is. In this year it's actually somewhat the same, but yes, exit-to-exit is how we look at it. All right. Thank you. Thanks, Timm. Thank you. I'll turn the conference back over to Willie Chiang for closing remarks. Hey, thanks, Chris. Hey, I just wanted to make a couple of comments. Hopefully it came through in our presentation. We worked very hard on this strategy and we've executed against it. Hopefully what you've seen is we've really positioned ourselves well. We're taking debt down. We've got this mantra of maximizing free cash flow. We've got a lot of operating leverage that we've talked extensively about, not only on volumes in the Permian, but some tariff uplift as we go forward. And then we've got a pretty rich opportunity set of low cost debottlenecks and continued opportunities around our existing system. We hope you look at slides 13 and 14 because I think that really encompasses what we've been trying to do and where we're headed going forward. With that, I'll thank you all for taking the time to spend with us this afternoon. Thank you. This concludes today's conference call. Thank you all for participating. You may now disconnect and have a good day.