© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, and thank you for standing by. Welcome to the PAA and PAGP Fourth Quarter Full Year 2021 Earnings Conference Call. [Operator Instructions]. 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 consolidating balance sheet for PAGP and other reference materials are located in the appendix.
Today's call will be hosted by Willie Chiang, Chairman and CEO; and Al Swanson, Executive Vice President and CFO. Other members of our team will be available for the Q&A 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, and 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 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, 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 2 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 goals set out in February to maximize free cash flow, complete our multiyear 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 of 2020. We also completed our multiyear 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. 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 3 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 efficiency -- 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 5 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 $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 to 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 multiyear basis supported by our integrated business model from producing regions to key markets 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 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 [ court ]. 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 as 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 plus or minus 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 assumption 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 7 months of earnings from our gas storage assets and onetime 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 Plains to investment grade in November. As shown on Slide 11, we established a new leverage ratio, which closely aligns with the rating agencies leverage calculation, and we are targeting a range of 3.75x to 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 our -- 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 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 million to $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, 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 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 4 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. [Operator Instructions]. 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.
[Operator Instructions]. Our first question comes from Keith Stanley of Wolfe Research.
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 guidepost you would use to size the ultimate dividend once you hit your balance sheet targets?
Yes. Thanks, Keith. Let me start by saying we've had an annual dividend policy review, a 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 after distribution and we've articulated a wedge, 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 -- cash flow from operations as kind of a metric going forward. Al, do you want to add anything to that? Does that help, Keith?
That helps. Separate question. Just looking at the waterfall on Slide 9. And 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 pipeline 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?
Well, Keith, I've got 2 comments on that: one, we highlighted -- there is a significant shift with the 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 catching up with -- starts balancing with capacity.
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 Wink-to-Webster as having a headwind on the company in 2022? Or is it more a volume issue? [indiscernible] headwind.
Well one comment -- so a good example of that would be the basin pipeline, which does not have MVCs. In 2021, where you 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?
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 will -- it's 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 pull back on the basin system. So there's going to be ratable demand to Cushing, 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 ratable. 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. The -- as far as your question on Gulf -- 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 diff -- there's 2 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 a T&D 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 a 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 barrels across the system and look to fill them as we always have.
Our next question comes from Michael Blum of Wells Fargo.
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. 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 because that's going to fill MVCs and the ramps on Wink-to-Webster and others. So there's a 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 2 years of growth consistent with last year, then you start to get leverage on increasing spreads to the Gulf Coast into markets outside. And there's also a volume component of 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 tariffs. And it's not single touch, it's multiple touch barrels. So hopefully, that's helpful.
It is. 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 for the -- in terms of guidance, what's driving the year-over-year improvement in the NGL segment? I think the EBITDA is up like 33% per the guidance?
Yes. So Michael, there's a couple of things. It's primarily Canada. We do have some terminals and we've got some facilities in the lower 48, but it's primarily of 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 frac spread environment. And part of the reasons we've resegmented it is, I think it will allow people to see the 2 segments a little -- with a little more transparency as we talk about the business, it's certainly how we think about it. So -- but probably the biggest driver is the difference in the frac spread environment between last year and this year.
Next, we have Jean Salisbury of Bernstein.
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 want to flare this time around?
Well, I can tell you, Jean Ann, definitely, if there's -- people are not going to flare. So there's going to be pressure 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 2 or 3 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 their 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.
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 to 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 allow 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 talked to or are 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 0.5 Bcf a day that's out there with the [ Whistler ] project, that should help and maybe extend that a couple of quarters or so.
But you're right, the flaring is something that could -- we've seen in the last 6 months caused intermittent disruptions in the field. They will not flare. So there's a problem with a processing plant. So the industry is in a good way, that's from an ESG perspective, people go in to lower carbon. That's one way we're seeing very actively managed on the producer side. But we do take that into consideration of our forecast, and we're cautiously optimistic the industry will come to a solution.
Great. 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 will not -- is sort of one of the more -- 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?
Jean Ann, this is Jeremy. 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 [ honestly ] for us to convert something to a gas line.
And next, we have Jeremy Tonet of JPMorgan.
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 '22 guide really have nothing on the S&L 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.
Yes, Jeremy, there's a lot of volumes that shift [ for ] 4Q 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?
Yes. 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 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. 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 synergies with Oryx or initial projects there. And that's the key driver there. And it will come down in future years? And then I guess, buybacks versus dividend, we were kind of thinking that the buyback 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 how you view that going forward.
Al, why don't you take a shot at this?
Yes, sure. We look at between the way we all allocate capital back to equity holders is a balance between the 2, 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 and accomplish both, so to speak. I think the capital is pretty much in line. I think this year, we're showing a "consolidated" of investment capital of about $330 million net $275 million. 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.
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.
Jeremy, let me just add to that a little bit. 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 $0.15 annualized is really the conviction that we have in our cash flow stream going forward. And to Al's point, it's -- 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.
Next, we have Tristan Richardson of Truist Securities.
I appreciate all the comments on the new segments. And just -- 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 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 [ 8/8 ] volumes versus a net EBITDA to PAA comparison?
Or -- but 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?
Yes, this is Al. I'll take a shot. Yes, as we collapsed all of the crude business into one segment, and we have been reporting crude activity under 3, as we looked at it, we didn't believe that we should necessarily try to choose 1 or 2 "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 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 calculation for it. And 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.
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.
Appreciate it. And then I guess just -- you talked about kind of priorities for CapEx and maintenance CapEx really being connected -- well connect -- focused. You also talked about asset optimization that be [ Brownfield ] expansions and JVs. Could you give us a sense of maybe 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.
Yes, 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, our fractionating facilities. It looks like we have some low-cost expansions available there that would enable additional throughput, 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 a 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.
Tristan, just to add to it. When you think about our NGL business, we've got large complexes that are straddle plants/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, that system -- that facility has been set up is we've had multiple owners, joint venture partners. And what we're doing now is 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 the operating side is there's a number of optimization opportunities to run the 6 -- 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.
And next, we have Becca Followill of U.S. Capital Advisors.
I think you talked about earlier about $150 million of synergies for 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?
So Becca, the -- we never quoted $150 million in 2022. It was $50 million in 2022, It is as growing to $100 million longer term. And so those are both [indiscernible] number. And Jeremy, do you want to 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 going to be in lower CapEx, it will create. We had capital in our standalone plan to capture some opportunities, which would require capital. Having the Oryx system merge with the Plain system eliminates that. Having the ability to connect dedications from one system to the other to shorten laterals as part of that. So let's call that half of the capital synergies 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 2 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 it's costs, some of it's capital, some of it's commercial, and we think we'll step into more as we get to know the system. We've had it for 3 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.
And then 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, do you want to take that?
Sure. Think of the frac spread exposure being buying AECO gas and selling plus or minus a nickel, Mont Belvieu-type basis on the NGL side and the C3 plus. And its cost reimbursement for ethane is basic structure to think about. So 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 in earlier in the year or in late 2020. So that step change from an overall frac spread in the 50s to north of $0.70 is what you're thinking about. So $0.15-plus in frac 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.
Next, we have Michael Lapides of GS.
I actually have a couple of them. Just -- I wanted to sanity check one thing. I'm looking at fourth quarter volumes in the Permian and about 5.2 million, 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?
This is Jeremy Goebel. Yes. And part of that is the 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 at one of 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 '22 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 pull 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 how you're -- 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 is there a stag -- can you remind us -- is there a staggering of when the contracts go into effect? And when is kind of that year where they're all in effect or they all start to be in a fully in effect for both lines?
Sure. Wink-to-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 2 years, ratable increases from there to get to full. So maybe 2 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.
Next, we have Chase Mulvehill of Bank of America.
A couple of kind of questions. I mean some of this has been discussed, but 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 the follow-up is with the same question when -- what does Permian oil production volumes -- what do they need to get to to see kind of a pickup in Cushing volumes?
So Chase, I'll start. And I do want Jeremy to talk about it because 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've maybe taken 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 the spare capacity and spot tariffs and MVCs and 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. And then next year's production growth will fill Wink-to-Webster plus any shorts in the market today. So you basically get back to an environment where people are not remarketing the space within the next 2 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 discounted 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 forecast. And at that point, you filled all existing MVCs, you have spot barrels, which changes the dynamic. And 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. 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 [ valve ]. Midland weakens relative to the other markets. And so Cushing becomes more competitive in all markets. So it is a dynamic market. It doesn't sit still. But hopefully, that gives you enough to run with.
Yes. Yes. 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 so basically, what I'm hearing is you got about 1.2 million barrels a day of Permian oil production growth where 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 [indiscernible] 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 [indiscernible] fill space. So it's dynamic. But in this 30 seconds, yes, that would be our assessment.
Next we have Brian Reynolds of UBS.
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 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 distributions and potentially buybacks. Is that a fair way to think about 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.
Yes. 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 be reflected before any increase this year. There's 2 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. And if you think about this blue, 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 unitholders. And that's the point we really want you to take away.
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 '22 is filling the Wink-to-Webster, MVCs, et cetera. Well, in '23, is that where we could see volumes moving above MVCs on the legacy Plains' pipes and start seeing that material earnings uplift?
Yes. I think that was -- 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 your market limited at this point. The Midland MEH spreads $0.20 to $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. 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. So it's -- but to your point, on the balances, there are some limitations on that. And so some time in the -- as I said, 18- to 24-months from now, we're -- from the beginning of this year, you end up in a period where we think that starts to rebalance.
Chris, I think we have time for one more analyst's questions. So we'll take this next set of questions and then call the call.
Our last question comes from Timm Schneider of Citi.
Real quick. So if I back into 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 '22? Or is that longer dated?
Jeremy?
I would think of that as a continuous program, and that's a gross number of $150 million. So think of that as $100 million net to Plains. 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 ratable amount largely. And so you think that cycle is largely continuous. So the cycle of the projects, whether it's 4- to 6-months realistically, we have that as a continuous program. So every month, 4- to 6-month projects are finishing. It's not -- 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.
Okay. Got it. And then just shifting gears to back to Oryx. You said capital synergies, $50 million going to $100 million, but what's the actual EBITDA contribution that you're forecasting net to Plains of Oryx in 2022?
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.
Okay. Got it. And then -- sorry, go ahead.
I was just anything that reduces sustaining capital to us is free cash flow generating. And so that's how we're looking at the business.
Okay. Understood. And then 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.
[indiscernible] I'll turn the conference back over to Willie Chiang for closing remarks.
Thanks, Chris. I just wanted to make a couple of comments. Hopefully came through in our presentation. We 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 for 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 systems. 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.
This concludes today's conference call. Thank you all for participating. You may now disconnect and have a good day.