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spk02: 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 in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during that session, you'll need to press star 1 on your telephone. And if you require any assistance during the call, please press star 0. I would now like to hand the conference over to your speaker today, Mr. Roy Lamoureux. Mr. Lamoureux, the floor is yours.
spk05: 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 two. A condensed consolidating balance sheet for PAGP and other reference materials are located in the appendix. Today's call will be hosted by Willie Chang, Chairman and CEO, and Alice Watson, Executive Vice President and CFO. Other members of our team will be available for the Q&A session, including Harry Pafanis, 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, Willie.
spk14: Thank you, Roy. Good afternoon, everyone, and I want to 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 a year in 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 plain 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 four, 2021 was a year of solid execution for us in a competitive environment. Overall, we executed well, and we achieved our goals 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 a billion dollars 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 of 2020. We also completed our multi-year capital program with both the cap line reversal and Wink to Webster projects now in service. We are also well on our way to integrating our premium assets with the OREC 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. And 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%. And 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 15 cents 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 five. 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 three to four million barrels a day in 2022, and continued growth for the foreseeable future. We expect this demand growth, combined with the multi-year backdrop 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.
spk13: 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 intersegment 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 six. 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 seven and eight. 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 plus or minus 4.25 times, 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 escalations, 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 plans 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 3.75 times to 4.25 times. 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 multi-year build-out, we remain disciplined and focused on must-do, no-regrets capital. Net-to-plains, we expect 2022 investment capital of plus or minus $275 million and maintenance capital of plus or minus $210 million, inclusive of a $35 million NGL facility turnaround. Going forward, we expect annual run rate investment and maintenance capital of $250 to $350 million, and less than $200 million, respectively. This includes approximately $50 million of capital related to non-controlling interest. 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, a 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 plus or minus $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 rate 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.
spk14: 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 multi-year 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. And 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 want to 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.
spk05: 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.
spk02: Thank you. And again, to ask a question, please press star 1 on your telephone. To withdraw your question, please press the pound key. Stand by as we compile the Q&A roster. Our first question comes from Keith Stanley of Wolf Research. Your line is open.
spk04: 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. And 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 guideposts you would use to Sky is the ultimate dividend once you hit your balance sheet targets.
spk14: 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, so this is not a change from that. And we're going to continue that going forward. And the way I would look at our allocation, it's probably a little bit of a shift. We've talked about free cash flow investments. 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 unit holder in the forms of distribution increase as well as discretionary purchases. As we go forward, obviously that free cash flow we think is going to stay for a number of years, and as debt comes down, into 2023, the allocation will increase back to unit holders. And what we'll do is as we go forward, we'll start allocating against a percentage of free cash flow, a cash flow from operations as kind of a metric going forward. Al, do you want to add anything to that? Does that help, Keith?
spk04: That helps. Thank you. Separate question, just looking at the waterfall on slide nine. 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 eight, 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. 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're kind of already at MVC levels, so there's no real hit to EBITDA, if that makes sense?
spk14: 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. So that's a change between 2021 and 2022. And 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 capacity surplus capacity in that. And 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.
spk04: Okay. But I guess I thought you were already kind of running at MVC levels in 2021 on those long-haul pipes. So I guess, should we think of that shift to Winx to Webster as having a headwind on the company in 2022, or is it more a volume issue?
spk14: 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, and going into 2022, we expect more of those volumes to go to Wink to Webster. Jeremy, do you want to add anything to that?
spk15: 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 – some of the MVCs to Houston won't get filled as well. So I think it's a mix of pipelines across the industry because there's only a fixed amount of demand in Houston. So you can see that disproportionately impacted as well. I think of Basin as balancing the mid-continent when – inventories get low in Cushing like they are now, you're going to start seeing a pullback on the basin system. So there's going to be rateable demand to Cushing, and it's going to ebb and flow as you saw through the quarters last year. And as Permian Basin fills and Midland starts to weaken, you would see that more rateable. But think of that as somewhat cyclical throughout the year. So I think that mid-continent demand will largely be driven by refining runs in that area. As far as your question on pipelines to the Gulf Coast, largely protected by MVCs, but the spot capacity will represent what the market is. So 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-Webster will be a T&D level. Cactus 2 and Cactus 1, 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. So that will be one headwind, and then maybe a portion on volume. But by and large, we'll compete for Barrow's process system and look to fill them, as we always have.
spk04: That's helpful. Thank you.
spk02: Thank you. Our next question comes from Michael Blunn of Wells Fargo. Your line is open.
spk09: Thanks. Good evening, everyone. First question, I want to just ask about operating leverage. Basically, how much operating leverage do you have in the Permian as volumes ramp? Let's say that's 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?
spk15: Jeremy? Thanks for the question, Michael. So it's a little bit more nuanced than that. The first $600,000, think of the next 18 to 24 months on a long-haul basis if that's going to fill MVCs and the ramps on Wink to Webster and others. So 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. So 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. But 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 and to markets outside, and there's also a volume component to that spot volume. So it's not linear. It's going to have a certain impact this year and next year, which we view to be competitive markets but then it gets materially higher as you go because it's volume, it's tariff, and it's not single-touch, it's multiple-touch barrel. So hopefully that's helpful.
spk09: It is. Thank you. Second question on the NGL segment. I just wanted to confirm or clarify that the earnings coming from this segment are basically coming from the Canadian assets entirely, and I wanted to ask in terms of the guidance section, What's driving the year-over-year improvement in the NGL segment? I think the EBITDA is up like 33% per the guidance. Thanks.
spk14: Yeah, so, 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. And as you think about the difference between last year and this year, a big piece of that is the frack spread environment. And part of the reasons we've resegmented is I think it will allow people to see the two segments with a little more transparency as we talk about the business. It's certainly how we think about it. But probably the biggest driver is a difference in the frack spread environment between last year and this year.
spk09: Thank you. Appreciate it.
spk02: Thank you. Next we have Jan Salibury of Bernstein's. Your line is open.
spk01: Hi. Do you see the potential looming lack of Permian gas takeaway as a threat for Plains' growth post kind of 2023, 2024, if EMPs don't want to flare this time around?
spk14: Well, I can tell you, Jean-Anne, definitely if there's – people are not going to flare. So there's going to be pressure on – on gas takeaway, and we don't operate long-haul gas lines in the Permian, but if you hear others that are talking about that aligns kind of with your two or three years, 2024-ish timeframe, and at that point, I think there's going to 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, and 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. So I think it's something that we're going to have to continue to watch as we go forward. But there will be a constraint at some point in time. Okay.
spk15: Gina, 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. So the extent the production is coming from those It's the undedicated component that will have more restrictions. And so 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. So 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 BCAS today that's out there with the Whistler project, that should help and maybe extend that a couple quarters or so. But you're right, the clearing is something that could We've seen in the last six months cause intermittent disruptions in the field. They will not flare. So if there's a problem at a processing plant, so the industry is in a good way. From an ESG perspective, people going to lower carbon, that's one way we're seeing very actively managed on the producer side. But we do take that into consideration in our forecast, and we're cautiously optimistic the industry will come to a solution. Great.
spk01: Thank you. And then, 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 other pipelines in the basin might be.
spk15: Jean Ann, this is Jeremy. You know, you're going to need a thicker wall thickness and a higher diameter pipeline than the ones we have going to market. So I think it would be unwise for us to convert something to a gas line. Okay, great. That's all for me. Thanks.
spk01: Thanks, Gina Ann.
spk02: Thank you. And next we have Jeremy Tornay of J.P. Morgan. Your line is open.
spk10: Hi, good afternoon. Hi, Jeremy. Hi, I just wanted to dive into the guidance a little bit more with EBITDA and If I look at just 4Q here, and I know there's a little bit of seasonality in 4Q, but if I annualize the 4Q 2021 number, that comes up above the 2022 guide. And so I'm just wondering, does the 2022 guide really have nothing on the SNL side, or does resegmenting 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 4Q.
spk14: Yeah, Jeremy, there's a lot of volumes that shift for Q, 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?
spk15: 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. So 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. So there was just some timing of some sales in the NGL side and settlement of some MVCs. But 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.
spk14: That's a good point on the seasonality of the NGL. Definitely has an impact.
spk10: Got it. Thanks for that. And 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 the synergies with Oryx or initial projects there. And that's the key driver there. And it'll come down in future years. And 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 increases. 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, how you view that going forward.
spk14: Now, why don't you take a shot at this?
spk13: Um, Yeah, sure. We look at between the way we all allocate capital back to equity holders as a balance between the two, between distributions and repurchase activity. As an MLP, I think the primary approach for returning capital to our shareholders would be through distributions. So we think we can balance in 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 of investment capital of about 330 million net 275. So 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 seven, 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.
spk14: Thank you. 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. And what I would take away from the recommendation of the 15-cent annualized is really the conviction that we have in our cash flow stream going forward. And to Al's point, we don't see it as one or the other. We think we can do both. And we've proven that we can buy back shares as we demonstrated over the last year plus. And 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.
spk10: Got it. I'll leave it there. Thank you. Thanks, Jeremy.
spk02: Thank you. Next, we have Tristan Richardson of Truth Securities. Your line is open.
spk03: Hey, good evening, guys. I 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 per transport barrel, but If I just look at 22 crude segment volume guidance against the crude segment EBITDA, it 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 eight-eighths volumes versus a net EBITDA to PAA comparison? 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 I guess you used to talk about even thought per barrel.
spk13: 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, again, Ultimately, there are variations to it. What we did historically wasn't perfect either. Over time, we had changed volumes when we thought there was 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 in lease out, as well as our lease purchase activity, But 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 calculations for it. And again, 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. So anyway, we recognize it's not perfect, but that's why we chose not to, because 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. And similarly on the NGL side.
spk03: I appreciate it. Thanks, Al. And then I guess just, you know, you talked about kind of priorities for CapEx and maintenance CapEx, really being connected, you know, well Connect 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?
spk12: Chris? 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. And then along the ESG lines, we fundamentally believe that... Energy efficiency at the end of the day is also good business. So we're looking at opportunities to reduce energy consumption and increase energy efficiency at some of our assets that are large energy consumers. And we see some opportunities there as well that we'll look to fund if they meet our return thresholds.
spk14: 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 slash fractionation facilities. So 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, and what we're doing now is we'll recall we swapped our Milk River asset for portions of that by being able to clean up if you will, the ownership structure, both the commercial side and operating side, is there's a number of optimization opportunities to run the six, Empress 1 through 6, more of a system versus being constrained with each one with different owners. So 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.
spk03: Appreciate it. Willie, Chris, thank you guys.
spk14: Thanks. Thanks, Kristen.
spk02: Thank you. And next we have Becca Folliwell of U.S. Capital Advisors. Your line is open.
spk08: Hi, guys. Thanks for taking my call. I think you talked about earlier about $150 million of synergies from orgs, 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?
spk14: So Becca, we never quoted 150 in 2022. It was 50 million in 2022 8As growing to 100 million longer term. And so those are both 8As number. And Jeremy, do you want to articulate where you might see some of the synergy numbers?
spk15: Sure, Becca. I think it's all of the above. I'd say roughly half of that is probably going to be in lower CapEx. It'll create We had capital in our standalone plan to capture some opportunities which would have required capital. Having the OREC system merged with the plane system eliminates that. Having the ability to connect dedications from one system to the other to shorten laterals is part of that. So let's call that half of the capital centers in spite of inflation able to reduce that $50 million by roughly half. And then 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. And our goal is obviously to beat that, but that's what we stack our hands on today and feel like we can capture some of its costs, some of its capital, some of its commercial, and 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. So we're excited about it. And as Willie said in the beginning, we're comfortable with the $50 million and we'll look to grow from there.
spk08: Thank you. And then just following up on Michael Bloom's question on equity, the NGL segment guidance, you talked about a big piece of the frack spread environment. Can you talk specifically about what has changed in the frack spread environment?
spk15: Jeremy, you want to take that? Sure. Think of the frack spread exposure being buying acogas and selling plus or minus the nickel Montvelde type basis on the NGL side, and it's C3 plus, and it's cost reimbursement for ethane. It's basic structure to think about. So, As you think of the run in liquids prices relative to natural gas, the frack spread has increased materially. Some of the hedges put on last year were done earlier in the year or in late 2020. So that step changed from an overall frack spread in the 50s to north of 70 cents is what you're thinking about. So 15 plus cents in frack spread across the whole program. is largely driving that exposure. There's also a portion that's volume. The colder weather in the Northeast is driving incremental demand through our straddle plants, which is increasing volume. So it's some volume, some margin, but by and large, it's the commodity exposure in that portion of the business.
spk08: Great. Thank you.
spk15: Thanks, Becca.
spk02: Thank you. Next, we have Michael Lippies of GS. Your line is open.
spk16: Hey, guys. Thank you for taking my question. I actually have a couple of them. Just I want to sanity check one thing. I'm looking at the fourth quarter volumes in the Permian at about 5.2, 5.3 million barrels a day. So your guidance for 22 basically assumes that you're going to be flat relative to the fourth quarter actuals. Am I thinking about that right?
spk15: This is Jeremy Goble. Yes. And part of that is the 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% to 100%. So total gross volumes are up, but net to our interest, they're down. But you've seen any reduction there, you're seeing offset by increased growth on the gathering system. And as we said before, this is consistent with what we'd expect to see in 2022 and potentially part of 23 of the growth projections we have, but 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.
spk16: Understood. The benefit of it should compound over time. The other question I had, I'm just curious how you're, you know, when we think about both Wink to Webster and CapLines, How long should we think about the timeline is for each of those to ramp up into kind of a normalized EBITDA run rate? 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?
spk15: Sure. When you think of Webster, think of it as a significant portion of the volume kicked in in February of T&Ds. And then think about it over the next two years, rateable increases from there to get to full. So maybe two years from now, you'll largely be fully ramped up in MVCs. As for CapLine, it started at where we have 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.
spk16: Got it. Okay. Thank you. Much appreciated, guys. Thanks, Michael.
spk02: Thank you. Next, we have Chase Mothill of Bank of America. Your line is open.
spk11: Hey, thanks for squeezing me in here. A couple of kind of questions. I mean, some of this has been discussed, but I just want to dig a little bit deeper. But could you talk about 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, And then, you know, the follow-up is the same question, you know, what does Permian oil production volumes, what do they need to get to see kind of a pickup in Cushing volumes?
spk14: So, Chase, I'll start. I do want Jeremy to talk about this because he lives this 24-7. When you think about our system, we get a lot of questions on why barrels aren't flowing in 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. But there's a unique situation going on right now with spare capacity and spot tariffs and MBCs in production. Jeremy, would you kind of share your thoughts on that?
spk15: Sure. Go ahead. The way I think about it simply is that this year's production growth will go to fill the incremental MVCs on Wing to Webster plus a little bit. And then next year's production growth will fill Wing to Webster plus any shorts in the market today. So 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. And at that point, pipeline tariffs you start to ship at incremental spot tariffs first, shipping at some market at this kind of level just to fill space. And so that probably answers all of your questions, but that's just the way we're looking at the market. So it's going to be a competitive market for the next 18 to 24 months at current production forecasts. And at that point, you've filled all existing MVCs, you have spot barrels, which changes the dynamic. And 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. But 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 value. Midland weakens relative to the other markets, and so Cushing becomes more competitive all markets. So it is a dynamic market. It doesn't sit still, but hopefully that gives you enough to run with.
spk11: Yeah, 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. And, you know, so basically what I'm hearing is you've got about 1.2 million barrels a day of Permian oil production growth where you really start seeing some kind of, you know, significant operating leverage across the long-haul pipes. Is that a fair assumption?
spk15: I think at this point it is, but remember that's dynamic because it's a lot of other pipelines. then that number gets smaller. So it doesn't have to stay that way forever, right? It's just as MVCs roll off on other pipelines, we control substantial balancing fill space. So it's dynamic. But in this 30 seconds, yes, that would be our system.
spk11: Okay. Great. That's all I had. I'll turn it back over. Thanks.
spk15: Thanks, Chase.
spk02: Thank you. Next we have Brian Reynolds of UBS. Your line is open.
spk07: Hi, good evening everyone. Start off on capital allocation as a follow up to some of the previous questions. We 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? I'm just kind of curious as we go forward and reduce that further, Just wondering if more free cash flow could go towards distributions or buybacks beyond 22. Thanks.
spk14: Yeah, so Brian, I think your math is pretty close. If I take you back to the slide that we show this on 13, 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 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. And if you think about this blue and what's circled in the yellow, our goal is to get our leverage down. But once that happens, it gives a significant amount of capacity to return to unit holders. And that's the point we really want you to take away.
spk07: Great. That's helpful. And then as a follow-up on some of the previous Permian guidance questions as well, just want to clarify, it seems like, you know, 22 is, you know, filling links to Webster, MVCs, et cetera. While on 23, is that where we could see volumes, you know, moving above MVCs on the legacy planes pipes and start seeing that, you know, material earnings uplift? Thanks.
spk15: I think that it's very consistent with the last question. So, That's the starting point. We're going to look to continue to attract incremental spot barrels, but we're not going to overpay because you're market limited at this point. The Midland MEH spreads 20 to 30 cents. There's no sense in if we can get a 10-10 premium selling at Midland versus consuming 15 cents of power and taking the risk of marketing barrels, it's better to sell it at Midland. So 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 going to move barrels to Cushing. But to your point on the balances, there are some limitations on that. And so sometime in the, as I said, 18 to 24 months from now or from the beginning of this year, you end up in a period where we think that starts to rebalance.
spk07: Great. Appreciate the cover. Have a great evening, everyone.
spk05: Thanks, Brian. Hey, Chris, I think we have time for one more question. One more set of analyst questions, so we'll take this next set of questions and then call the call.
spk02: Yes, thank you. Our last question comes from Tim Schneider of Citi. Your line is open.
spk06: Hey, thank you. Real quick, so if I back into the $150 million or so of WellConnect 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?
spk15: Jeremy? I would think of that as a continuous program. And that's a gross number, $150 million. So think of that as $100 million net to planes. And returns on that, it's going to be like declines in wells. So it's going to be continuous. Every month, we're connecting a rateable amount, largely. And so you think that cycle is largely continuous. So the cycle of the projects, whether it's four to six months, Realistically, we have that as a continuous program. So every month, four- to six-month projects are finishing. Don't view that as a large pipeline where it starts and 18 months later you get capital. That is a continuous piece of capital that's maintaining cash flow and generating substantial returns associated on a standalone basis.
spk06: Okay, got it. And then shifting gears 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-to-plains of Oryx in 2022?
spk15: Sure. That's an 8-8 number, so if you take 65% of that, and then, like I said, the contribution in 2022 is half capital, half EBITDA-generating concepts. So 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.
spk06: Okay, got it. And then last... Sorry, go ahead.
spk15: I was just saying, anything that reduces sustaining capital to us is free cash flow generating, so that's how we're looking at the business.
spk06: Okay, understood. And then the 600,000 barrel a day increase, is that just to clarify, is that an exit-to-exit number?
spk15: It is, and this year it's actually somewhat... The same, but yes, exit to exit is how we look at it.
spk06: All right. Thank you.
spk15: Thanks, Tim.
spk02: Thank you. As that was, I'll turn the conference back over to Willie Chang for closing remarks.
spk14: Hey, thanks, Chris. Hey, I just wanted to make a couple of comments. Hopefully it came through in our presentation. We've worked very hard on this strategy, and we've executed against it. And 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 de-bottlenecks and continued opportunities around our existing system. So 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. So with that, I'll thank you all for taking the time to spend with us this afternoon. Thank you.
spk02: This concludes today's conference call. Thank you all for participating. You may now disconnect and have a good day.
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