Good day, and thank you for standing by. Welcome to the PAA and PAGP first quarter 2022 earnings 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 the session, you will need to press star one on your telephone. If you require any further assistance, press star zero. I would now like to hand the conference over to your speaker today, Mr. Roy Lamoreaux. Please go ahead.
Thank you, Tino. Good afternoon, and welcome to Plains All American's first quarter 2022 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, and an overview of today's call is provided on slide 3. The consolidated, consolidating, or 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 Chief Financial Officer.
Other members of our team will also be available for the Q&A, including Chris Chandler, Executive Vice President and Chief Operating Officer, Jeremy Goebel, Executive Vice President and Chief Commercial Officer, and Chris Herbold, Senior Vice President, Finance and Chief Accounting Officer. With that, I will now turn the call over to Willie.
Thank you, Roy, and good afternoon, everyone, and thank you for joining us. Well, our business is off to a strong start to the year, reporting solid first quarter Adjusted EBITDA attributable to PAA of $614 million, which is above our previous expectations. Given the quarter performance and our outlook for the balance of the year, we are increasing our full year 2022 guidance for Adjusted EBITDA by $75 million to ±$2.275 billion with a bias to the upside. This is primarily driven by constructive fundamentals and the associated benefits of a higher commodity price environment within both our crude and NGL segments. Al will provide more detail on our quarterly results and our full-year outlook in his portion of the call.
Current global events have highlighted and reaffirmed the importance of hydrocarbons in everyday life, spurring a renewed focus on energy security and the need for safe, reliable, and responsibly produced energy. The North American energy industry plays a critical role with abundance of resources, access to capital, a skilled labor force, and innovative technology. We believe the call on North American shale, more specifically the Permian, will remain strong for decades and that our integrated midstream asset base and business model will play a critical role connecting energy supply with global demand. As shown on slide 4, we are executing on our levers for maximizing unit holder returns.
In the Permian, we continue to expect at least 600,000 bbl per day of production growth in 2022, of which we anticipate capturing approximately an incremental 280,000 tariff bbl per day on our Permian gathering systems year-end of 2021 to year-end 2022. As a result of our system flexibility and operating leverage, we have added an incremental 45,000 bbl per day of contracted short-term volumes to our Permian long-haul pipelines versus our full-year expectations in February. As Permian production continues growing beyond 2022, we expect meaningful growth on both our gathering and long-haul systems. In our NGL segment, we expect continued growth in western Canada gas production and improving NGL supply and demand fundamentals combined with a higher price environment.
This drives our focus on optimizing and debottlenecking our existing facilities and operations to allow additional volume capture over the next several years. Additionally, we continue pursuing capital-efficient emerging energy opportunities, such as the recently announced MOU with Atura Power, which is a subsidiary of the Ontario government, to conduct a feasibility study which could result in adding hydrogen storage capability at our Windsor, Ontario salt cavern storage facility. This would directly support Atura Power's Brighton Beach generation station and aligns with a larger hydrogen strategy outlined recently by the province of Ontario. Regarding our financial strategy, we expect to continue generating significant multiyear free cash flow, and we will allocate this cash in a balanced manner to maximize unit holder returns. Our near-term focus will continue to prioritize debt reduction while also increasing cash return to equity holders and making disciplined capital investments.
In that regard, we announced a $0.15 per unit annualized distribution increase last month, and we have cumulatively repurchased approximately $250 million of common equity under our repurchase program since inception. As shown on slides 5 and 6, demand recovery contrasted against the multi-year backdrop of reduced upstream investment is causing a tight supply and demand balance, resulting in global inventories drawing down and hovering at multi-year lows, all of which underpins a higher commodity price environment. The conflict between Russia and Ukraine has further exacerbated market tightness and increased commodity price volatility.
We expect U.S. shale production led by the Permian will continue to be crucial to supplying and meeting global energy demand with Plains' integrated system and business model well positioned to benefit and generate significant multi-year free cash flow. This is supported by our Permian gathering system and 4 million dedicated acres, with approximately half of the total horizontal Permian rigs currently located on that acreage. Our highly contracted long-haul pipelines and meaningful Permian operating leverage, as well as our existing critical infrastructure in other key producing North American bases. Furthermore, high levels of cash flow and strong distribution coverage position us to reach our leverage target in mid-2023, with meaningful capacity to further increase cash returns to equity holders and drive strong unit holder returns both near and longer term. With that, I will turn the call over to Al.
Thanks, Willie. We reported first quarter Adjusted EBITDA of $614 million, which includes the benefit of NGL seasonality, higher volumes and commodity prices, and the startup of the Capline and Wink to Webster Pipelines. Slides 7 and 8 contain quarter-over-quarter and year-over-year segment Adjusted EBITDA walks, which provide more detail on our first quarter performance. A summary of our 2022 guidance is located on slides 9 through 11. We've increased our full-year 2022 Adjusted EBITDA guidance by $75 million to ±$2.275 billion. The increase is driven by several factors, including the benefit of improved frac spreads and volumes in our NGL business, and improvements in our crude oil segment, including increased volumes benefiting our Permian system, as well as higher pricing on pipeline loss allowance barrels, partially offset by reduced merchant opportunities.
As detailed in our earnings release, we reached agreements in principle to settle two class action lawsuits regarding Line 901 and recorded a $85 million increase in our net expense associated with the Line 901 incident, which has been treated as a special item impacting comparability and excluded from Adjusted EBITDA. The first is a class action lawsuit pending in federal court in California, which is proposed to be settled for $230 million. We believe this will be substantially reimbursed by insurance. The second is a derivative suit pending in Delaware Chancery Court, and the proposed settlement includes the payment of approximately $2 million in attorney's fees and other non-financial terms.
More information regarding the settlement of these matters and the changes to our Line 901 accruals are set forth in the Line 901 update included in the earnings press release. An overview of our current financial profile is provided on slide 12. We remain focused on generating significant free cash flow and allocating it through a balanced approach that reflects a continued focus on debt reduction in the near term. For 2022, excluding the anticipated impacts of the Line 901 settlement and our estimate of timing of the insurance reimbursement, our free cash flow guidance is relatively unchanged. Giving effect to this timing, we have reduced our guidance by $150 million.
Importantly, the impact is expected to reverse over the next 12 months, and our year-end 2022 leverage guidance remains at ±4.25 times. Accordingly, we are maintaining the amount of cash available to be allocated to discretionary unit repurchases for 2022 from what we indicated in our February guidance, which was approximately $100 million. Our capital program outlook is unchanged from last quarter and is summarized on slide 13. We remain committed to capital discipline and expect consolidated 2022 investment capital of ±$330 million and maintenance capital of ±$220 million. A summary of our capital allocation framework is on slide 14.
In the first quarter, we repaid $750 million of senior notes and repurchased 2.4 million common units for $25 million, leaving up to $75 million available for potential discretionary repurchases over the balance of the year. Additionally, in response to feedback, we have included several slides in today's appendix, which are designed to provide additional detail and improved visibility into our new crude oil and NGL segments, both from a historical and forward-looking perspective. With that, I'll turn the call back over to Willie.
Thanks, Al. Our business is off to a very positive start in 2022, supported by constructive fundamentals, a favorable commodity price environment, and increasing volumes on our Permian JV and long-haul systems. As such, we remain well positioned to continue executing against our 2022 goals as outlined on slide 15. Before opening the call to Q&A, I'd like to share some comments on our longer term outlook and how we position ourselves for 2023 and beyond. As I stated earlier, we believe that Permian will be critical to meeting increased global oil demand. Slide 16 shows our Permian production outlook against current takeaway capacity out of the basin. Our February outlook for production reflected growth of roughly 600,000 bbl per day per year over the next several years, increasing to 7 million bbl by 2025.
We currently have a slight positive bias to our production forecast, and we will update that if appropriate later this year. Any meaningful incremental production above the 600,000 bbl per day growth should benefit our systems. Looking at Permian takeaway, the current mainline capacity is approximately 8 million bbl a day, of which we believe that slightly greater than 7 million bbl a day, or roughly 90% is the efficient operating capacity. As production and long-haul utilization continue to increase, spare capacity will begin tightening and tariffs to the water should return to a more normalized level.
In fact, we've begun to see the early innings of this in forward markets, as indicated by the Midland U.S. Gulf Coast spreads to the water doubling in 2023 to approximately $0.08 per bbl and tripling in 2024 to approximately $1.25 per bbl from today's prompt month of approximately $0.40 per bbl. My point is, Plains has a critical asset base in a key producing basin, and we have pipe in the ground with meaningful available capacity across our system with minimal CapEx requirements. Our integrated business model and asset base allows us to move energy to multiple markets safely, reliably, and responsibly, and will benefit from any production accelerating beyond our current expectations, whether it's capturing additional growth or improved long-haul margins from current market levels today.
As illustrated on slide 17, in recent years, we've taken numerous steps to position our business to be successful in any environment. We've strived for operating excellence, improving our safety and environmental metrics greater than 50% since 2017. We've continued to optimize our asset base, focused our business by completing over $4.5 billion of non-core asset sales and created additional alignment through 15 JVs, strategic joint ventures, and most recently forming the Permian Gathering JV, which is a system backed by 4 million long-term dedicated acres. Furthermore, we have continued investing in our key legacy assets while exercising capital discipline, creating operating leverage throughout the assets with minimal future capital requirements. In our NGL business, we continue to further optimize our facilities and operations through commercial alignment and are evaluating some high return de-bottlenecking opportunities.
Financially, we expect to continue generating significant multi-year free cash flow and achieve our targeted leverage by 2023, mid-2023. We have positioned ourselves to continue taking a balanced capital allocation approach, including our commitment to maintaining our investment grade rating and increasing overall returns to our equity holders. While we are focused on and expect capital efficient growth in our business, even at current EBITDA levels, we have a strong distribution coverage of approximately 250%, giving us meaningful capacity for growth and equity returns. In summary, we believe we are well positioned now and into the future. With that, I'll turn the call over to Roy.
Thanks, Willie. A summary of the key takeaways from today's call are provided on slide 18. As we enter the question and answer session, please limit yourself to one question and one follow-up question, and then return to the queue if you have additional questions. 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. Tino, we're now ready to open the call for questions.
All right. As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, please press the pound key. Again, that is star one to ask a question. First question comes from the line of Jeremy Tonet from JP Morgan. You are now live.
Good afternoon.
Hey, Jeremy.
Hey, just wanted to start off, I guess, with Oryx a bit more, and kind of how the integration is going there. Do you see, I guess, the integration leading to new commercial opportunities or just a bit more color, I guess, on progress there would be helpful.
Jeremy, why don't you cover that one?
Thanks, Jeremy, for the question. This is Jeremy Goebel. Look, so, based on when we formed the JV, it's outperforming expectations just from an activity standpoint as well as from a synergy capture standpoint. If we had to approximate today, it's roughly 10% ahead of schedule. We are getting closer to finalizing the integration process, but we do see more opportunities, but we're making sure we're operating safely and efficiently in providing customer service. We're actively in engagement with extending contracts with customers. I'd say it's going, certainly as well, but I would dare to say better than planned, and we'd expect to continue to grow that position. Customers are excited about it. It offers more service as we talk about more connectivity and optionality.
I think it's borne out to be good for the shareholders of the JV as well as the customers, and we'll look to continue to prove ourselves to the customers and grow the business.
Got it. That's very helpful there. You know, kind of pivoting towards, I guess, the energy evolution opportunities. You talked about the hydrogen storage opportunity there, and just wondering, I guess, how deep do you see the opportunity set at this point? You know, what's the path forward, I guess, with that to figuring out whether that's something real, and I guess could there be other hydrogen or other energy evolution opportunities, with converting existing assets?
Hey, Jeremy. This is Willie. Let me make a couple comments, and then I know Chris will talk specifically about the hydrogen opportunity. You know, as we've articulated before, we've got a pretty broad asset base, and the focus on emerging technologies is how do we integrate that in with our existing assets? Particularly around our areas of competency, as well as our asset base. When we think about things, it's how do you connect it in with the existing systems we have? Chris, can you cover the hydrogen piece?
Yeah, sure. This is Chris Chandler. What's exciting about hydrogen for this particular opportunity is it can be used as a means to store renewable energy. And the concept there is when there's excess renewable energy, you can use that to create hydrogen, and obviously you can store hydrogen, in our case, in underground salt caverns. It's a well-proven technology. It's been done across the industry for decades. In our case, our Windsor facility sits right next door adjacent to the Ontario Power Generation that Atura has today. We could repurpose existing caverns or develop new caverns very cost-efficiently to be able to store hydrogen.
Then in the middle of the night when the sun isn't shining or the wind isn't blowing, that hydrogen can be used to generate power with existing power generation assets like gas turbines or boilers. We're evaluating that particular opportunity in Ontario, but that technology can be applied everywhere, and the Canadian government's certainly interested in it in areas beyond just that particular location. With our storage position across Canada, we see multiple opportunities for similar technology adoption.
Got it. That's very helpful. I'll leave it there. Thanks.
Thanks, Jeremy.
Next one on the queue is Michael Blum from Wells Fargo. You are now live.
Thanks. Good afternoon, everyone. I wanted to ask first about volumes or production growth. Obviously the public E&Ps, it seems are staying on message in terms of capital discipline, but you and many of your midstream peers are talking about seeing higher volumes across your systems now and also into the rest of the year and beyond. Just wanted to try to reconcile that and see are you seeing any change in producer activity or messaging? Thanks.
Jeremy.
Michael, good afternoon. This is Jeremy Goebel. What I would say is it's consistent with what we stated in the first quarter. You saw volumes surge in the fourth quarter of last year, then December, January were somewhat soft, somewhat due to weather, somewhat due to solar completions. We've seen that cadence increase as you exit the first quarter and into the second, and it's largely driven by private operators integrated. The independents are talking about total production profile, so they are declining in other areas and growing in the Permian. Permian as a whole is consistent. Other basins are consistent with where we had them. By and large, based on what we see across the basin, we're seeing it trend in line to slightly above, as Willie said, and the producer mix is consistent with what we thought.
We see roughly half the activity within the basin on dedicated acres that Willie was talking about. That gives us pretty good insight. So far it's tracking. I'd say the things we're watching are labor and manpower. Natural gas takeaway seems to be getting solved. There are some governors on growth, but so far so good. Like Willie said, we have a positive bias that some activity probably gets brought from the beginning of next year to the fourth quarter, given the higher prices at this level versus where they were expected when they came into the year.
Michael, the only thing I would add is that Jeremy talked about you might pull some barrels in. The lag of additional activity is gonna be back-end loaded, but the most important piece is momentum into 2023.
Got it. Thanks for that. Other question I just wanted to ask was about the guidance, specifically the NGL segment. Just if you could just talk through the drivers there a little bit. Just wanted to make sure I understood how much of that is volume driven versus spreads. Thank you.
Michael, we've actually put some additional disclosure in the back, as a result of some feedback, number of feedback we got. I think what I'd like to do is ask Jeremy Goebel to walk through two slides there, which I think are one or two slides to kind of give you the perspective of how we look at the business, and that may answer your question. Jeremy?
Sure, Michael. If everybody could flip to slide 27, it's just an overview of the assets. I think the first thing that they see in general as we move NGLs west to east, we gather into Fort Sask, which is near Edmonton on the far west. We aggregate third-party supply. We fractionate, store, and transport for them to market. That's part of the third-party business. We actually buy some additional Y-grade as well as gather some Y-grade from Cochrane, and we move that east for further fractionation at Sarnia. At Empress, which is the next dot over, we extract. That's our largest straddle plant. We pull NGLs out in annual keep whole contracts and basically take the Y-grade, the NGLs in exchange for keeping whole on AECO gas.
We'll fractionate some there and sell into local markets on that PTC pipeline, or we'll move further east to Sarnia for further fractionation and sale. That's how it flows. When we talk about third-party business, a lot of that's around the Fort Sask and Windsor and St. Clair. Those would be two of the bigger locations for third party. Then when we talk about Empress and part of that Cochrane straddle, that's where we get the Y-grade that on the keep whole contract. If you could then flip to slide 30. If you look at slide 30, this gives you a sense for the breakdown. That fee for service business around the storage assets in the east and around the fractionation storage and transport assets in the west. That's at 35%.
The remaining 65% is associated with roughly 50,000 bbl a day of straddle. Think of that as roughly two-thirds at Empress and one-third coming off the Cochrane plant. That's the main driver. That 65% associated with the straddle is the key toll construct, and then the rest is the fee-for-service business.
Mike, does that help?
Yes, very helpful. Thank you.
Yeah. There's some additional information there on slide 31 that'll give you kind of the head profile that we've had. I think it'll allow folks to better understand our business.
All right, next one on the queue is Jean Ann Salisbury from Bernstein. You are now live.
Hi. I really appreciate the extra slides that you've added. I wanted to ask about slide 15, with your Permian growth and takeaway chart. Can you kind of talk about what you mean by efficient operating capacity with the 90%? Is that kind of your number with no drag reducing agents or something else?
Essentially, it is. As you start getting into the higher flow rates on the pipelines, you start to get less efficient. You know, certainly if you go back in time and you look at the 2014 and the earlier periods, there were times when the arbitrage opportunity was very, very significant and people utilized that capacity. A more normal efficiency point would be roughly 90%.
Okay. Would you say that it's fair that if people's concern, I guess, is just maintaining the rates that you have now, the 7 million bbl a day is kind of the right target versus production?
Well, what's shown on that is we haven't updated our guidance on production. It's still roughly 600,000 bbl a day per year with, as we pointed out, some our expectation for an upward bias. There are others out there that have higher production profiles than we do, and that's what's shown in the upside sensitivity. The way, Jean Ann, I would think about this slide is, you know, there was a view that it's hard for us to participate in any of the growth. What this is intended to show is that as growth increases, we clearly will get the benefit of that in our gathering systems as well as other systems. That definitely allows us to participate in the volume growth.
The other component of that is, as the utilization increases, we would expect that the arbitrage, as the forward market of my comments earlier, it starts to widen back out and get back to what I would call a more normalized environment. We would obviously benefit from that as we go forward with spot rates.
Yeah, no, that makes sense. I guess just as a follow-up on that, are you seeing any interest here in from customers on blending and extending contracts? I guess similarly, are you interested here in blending and extending?
Jeremy, why don't you talk about that.
Jean Ann, this is Jeremy. I'd say it's a combination of things. We are in active discussions and filling spot space at market rates on shorter-term deals. Through next year, most of our spot capacity is taken to the Gulf Coast at current rates or higher. The expectation is to keep it in shorter rates and then enter those dialogues when we get closer to what we view those normalized rates. Right now is not the time to enter into long-term deals. We're doing some, but they're stairsteps to match what the current market looks. We're not locking in these $0.40 tariffs for anything other than month-to-month. It's those 80+ cents that you do maybe a year, and then you look to some that maybe step up to that $1.25 level.
When you talk about blend and extend on some of our larger contracts, I think patience on both us and the operator, they're very comfortable with us on the gathering side, so we continue to extend those agreements to align for the longer term. We're very comfortable that we'll have the volume on the system and the customers on the system. It's just a matter of timing. Like we said, they're very happy with the arrangements we have today, and we'd look to extend those when we're both aligned on that. It's probably a next year thing than before it is today. That way they can make sure they get the space and we can make sure we have a constructive dialogue around aligning on longer term rates.
Great. That's really helpful. Thank you.
Thanks, Jean Ann.
Next one on the queue is Neel Mitra from Bank of America. You are now live.
Hi. Thank you. Just to follow up on slide 16 as well, very useful. It looks like in 2025 is with the upside case, you're at that 90% utilization and you hit that normalized rate. Any color on what that normalized rate is? I know you talked about the 2024 rate being about $1.25 with the forward curve, but when you hit up against that 90% or more, what do you expect that the rate should be?
Yeah. Neel, this is Willie. One of the purposes of us showing this is, I don't think it's a binary equation where you hit a certain point and you achieve a you know a different tariff rate. What we've typically seen is as you start ramping up and capacity gets you know tighter, you'll start to see an increase. You don't have to get to the 9% before you start seeing the increase. Ultimately, when you think about what a tariff rate might be, it really is gonna be set by what the incremental build, if you were to build a new pipeline, what that would cost. We expect that to be higher than perhaps it has been in the past.
The last round of pipes were built in 2019. As you go forward and you have to build new pipes, one could argue that with maybe some supply chain issues and steel costs and permitting issues, it gets more and more challenging. There might even be some upward price adjustment on what might the tariff be. Jeremy, do you have anything to add to that?
Yeah, no, I think Willie's correct in his assumption. That's gonna be based on term, origin, what other services are offered. We'd prefer not to speculate on that, but the forward market is indicating it, something that's getting more healthy and a more constructive dialogue between the carrier and the operator, and the industry's comfortable with it. We'll provide further guidance on longer-term rates as we get closer, if that's all right with you.
That's perfect. Thanks for the color. Just as a follow-up, kind of close to the 900,000 bbl a day that you control of crude. Could you walk through maybe some of the ways you're able to capture the commodity upside right now, whether it's blending or being able to control the barrel through long-haul pipes, et cetera? Just maybe what the short-term drivers are for right now.
We've got a very flexible system. What I would tell you is the immediate benefits of a higher priced environment is pipeline loss allowance. We have an increased. It's a higher price capture on that, so that would be something that's very easy to quantify. The other pieces between blending, arbitrage, contango storage, really depends on a lot of market issues. It's hard to point out specific things that we might be capturing other than point out that over a long period of time when the opportunities are there, we have a whole organization that focuses on being able to capture those opportunities. Jeremy, anything to add?
Yeah, I'd say that the other piece that's out of that is just from an activity standpoint with long-term dedications, more activity yields more tariffs. It's additional tariffs, higher PLA capture on the NGL business. Obviously, the frac spread exposure is there. We have those long-term dedications, also have the tariff escalators. So it's there a number of functions that capture that. Now, that's offset to some extent by costs on the operations side. If you have a large capital budget, there's additional costs there, but having a smaller capital budget or some is insulated. So I agree completely with Willie. Those were just a couple supplemental ways that we do benefit from inflation or higher prices.
Got it. Thank you. Appreciate it.
Thank you.
Next on the line is Brian Reynolds from UBS. You're now live.
Hi, good evening, everyone. Maybe just to follow up on a quick guidance question. You know, the $75 million guidance raise, just kind of curious if it really just relates to, you know, the Permian crude gathering volumes in the NGL segment with roughly no change on long-haul in terms of the EBITDA contribution.
I'm gonna let Al talk about that, but there is a component in that. We were able to get some additional long-haul shorter-term contracts done that added to our guidance numbers. The point I would make there is to reinforce what I just said earlier. You know, it's sometimes you can't. It's not a formula that you can look at. If the opportunities are there and it makes sense for the different partners, we've been able to add some short-term long-haul components in there. But you're right, it's volumes in NGL, volumes in crude, as well as pricing impacts both on PLA and frac spreads. Al, anything to add?
Yeah. No, you covered it. I think you summarized it. The NGL is more commodity-based. Crude had positive PLA pricing, positive volumes, partially offset by just lower merchant opportunities primarily up in Canada.
Great. Appreciate the color. Maybe just dive a little bit deeper into the long-haul segment. You know, it appears that you're receiving roughly 45,000 bbl per day of deficiency payments in your guidance for 2022. But it looks like you saw a 45,000 bbl per day upward revision in the long-haul volumes with the updated guidance. You know, on the last call, you talked about, you know, kind of anywhere from, you know, a year and a half to two years for the Permian to kind of soak up those excess spot barrels and with the Wink to Webster ramp, et cetera.
I was curious, you know, just based off of the guidance update with matching that 45- 45 for the 2022 guidance, whether that was potentially pulled forward to, you know, maybe a 1Q 2023 benefit where we could get above those MVC levels as it relates to Plains. Thanks.
You know, Brian, if I understand your question, trying to match up the barrels for barrels. I think the key point on the long-haul barrels is those are additional volumes we were able to capture. It isn't tied with a shifting of volumes anywhere, if that helps answer your question.
As it relates to potential earnings inflection, is kind of cadence the same as the last call, kind of still middle of next year, end of next year based off of just the Permian production outlook in terms of getting above MVCs?
Well, if I understand your question, it's what we're trying to show with 16 is that regardless of the MVCs, there's opportunities to capture additional volumes. Clearly on our Permian gathering sector, you know, we've got an additional capture on the slides of another 30,000 bbl a day versus what we had in February, which totals 280,000 bbl a day in the gathering system, right? That's a piece of growth that we are capturing. Then the other opportunities are opportunities that we'll catch when the opportunities present themselves. The key point I don't want people to walk away with is that until MVCs fill up, there's no opportunities for Plains to capture additional volumes, right?
That's part of our guidance and guidance upgrade is additional volumes we have been able to catch. The comment that was made in the fourth quarter call was, if you think about it just mathematically, you've got additional MVCs coming on, and if you were to mathematically match an additional production volume, that would be the theoretical number. There's always opportunities out there to capture additional barrels.
I think you heard that, Manella. We really appreciate the extra color on that. Have a great evening, everyone.
Thanks.
Next one on the queue is Becca Followill from U.S. Capital Advisors. Your line is now open.
Hi, Becca.
Hey, guys. Hey. There's a lot going on this afternoon. If you could just clarify, Dan, on the $150 million decrease in free cash flow, how much of that was working capital and how much of that was Line 901?
Al?
Primarily, we assumed and modeled it as Line 901. We believe there will be timing between the time we pay and the time we're ultimately reimbursed by insurance. We are assuming some increased working capital, roughly offset by, you know, the stronger performance that we're modeling in the company.
Perfect. The return of the insurance payments that's this year, or does that bleed into 2023?
No. That is. We're assuming some of the collections will straddle into 2023, so in theory that would be a higher. Our free cash flow will benefit in 2023 due to the timing.
Okay, thank you. That's all I needed. Thank you.
Thanks, Becca.
Next question comes from the line of Sunil Sibal from Seaport Global Securities. You are now live.
Yes. Hi, good afternoon, folks, and thanks for all the clarity. I just wanted to go back to the slide 30 again for a couple of seconds. Between the February guidance and your current guidance, between the three components of the pie chart, have you been able to hedge, you know, at better rates than than you were hedging in February? Or is it just that because the unhedged prices have moved up, you know, you're getting a significant upside?
Jeremy?
Sunil, this is Jeremy Goebel. I would say it's a combination of the two. We actively monitor, and when we see prices spike, we might layer in some additional hedges. Coming into this year, the hedges with the most recent hedges are at higher rates, and we've had additional volume, as Willie said. Part of the outperformance is border flows from Western Canada to the eastern markets have been higher, so we extract additional NGLs, and that's all at the spot rates. Those sales will be this year or next year, some combination. It's volume. It's a combination of incremental volume at unhedged levels, securing some additional hedges at higher prices, and then capturing the higher prices on the unhedged component, which is roughly 20% for the remainder of the year.
Sunil, just to make sure, the predominant amount of 2022 frac spreads is hedged.
Okay. Kind of follow-up to that, is the market deep enough for you to hedge 2023 also, or is that mostly, you know, unhedged?
Sunil, this is Jeremy again. We actively monitor it. Think of it as a rolling program. We have an active 2023, and once again, we're opportunistic around when they do that. We'll provide further guidance as we get into 2023. It's. We manage it. It's an operation and manage earnings associated, and we're trying to capture higher levels as well. We'll continue to update you on that. There is a deep enough market, and it's very thin in 2024, but 2023 is pretty active.
Got it. Lastly, could you remind us, you know, on the pipeline loss allowance, you know, how much is typically the bits you get on the volumes that you move as PLA? Or is there any other good way to think about that, you know, margin sensitivity?
2-3 million bbl.
Yeah. It's substantial. It's 2-3 million bbl a year associated with PLA, depending upon operating performance, and we continue to optimize around that. It's a big footprint. That's predominantly in the U.S. where we do collect that. It's substantial.
Got it. Thanks. Thanks for that.
Thanks, Sunil.
There are no further questions in the queue. I will now turn the call back over to the presenters.
Yeah. This is Willie. I'll just close with thank you for your participation on the call. I know there's a lot going on. We've appreciated feedback. We've had many discussions with folks, and as always, we're trying to further improve our disclosure and transparency in how we run the business. I do know that as we've changed our segments, there's an opportunity to continue to make improvements. Appreciate the support and feedback, and we'll look forward to updating you as we go forward. Thank you very much.
This concludes today's conference call. Thank you for participating. You may now disconnect.