Plains All American Pipeline LP Q1 FY2022 Earnings Call

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 speakers’ presentation, there will be a question-and-answer session. I would like to turn the conference over to your speaker today, Mr. Roy Lamoreaux. Please go ahead. Thank you, Chino. 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 of 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 highlighted on Slide 3. The 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. Thank you for joining us. While 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's 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 plus or minus $2.275 billion, with 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 in 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 unitholder returns. In the Permian, we continue to expect at least 600,000 barrels a day of production growth in 2022, of which we anticipate capturing approximately an incremental 280,000 tariff barrels per day on our Permian gathering systems by year-end 2021 to year-end 2022. As a result of our system flexibility and operating leverage, we have added an incremental 45,000 barrels a 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 that could result in adding hydrogen storage capability at our Windsor, Ontario salt-caverns 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 unitholder 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, the demand recovery contrasted against the multiyear backdrop of reduced upstream investment is causing a tight supply and demand balance resulting in global inventories drawing down and hovering at multiyear lows, all of which underpins a higher commodity price environment. The conflict between Russia and Ukraine has further exacerbated the market tightness and increased commodity price volatility. We expect US 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 multiyear free cash flow. This is supported by our Permian gathering system in four 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 and other key producing North American basins. 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 unitholder 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 plus or minus $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 an $85 million increase in our net expense associated with the Line 901 incident, which has been treated as a selected 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 the timing of the insurance reimbursement, our free cash flow guidance is relatively unchanged. Given the effect of 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 plus or minus 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 plus or minus $330 million and maintenance capital of plus or minus $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 segment, 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've positioned ourselves for 2023 and beyond. As I stated earlier, we believe the 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 barrels per day per year, over the next several years, increasing to 7 million barrels 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 barrels per day growth should benefit our systems. Looking at Permian takeaway, the current nameplate capacity is approximately 8 million barrels a day, of which we believe that slightly greater than 7 million barrels 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 indications of this in forward markets, as indicated by the Midland to US Gulf Coast spreads to the water doubling in 2023 to approximately $0.80 a barrel and tripling in 2024 to approximately $1.25 per barrel from today's prompt month of approximately $0.40 a barrel. So my point is, Plains has a critical asset base in a key producing basin, and we have pipelines 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 by 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 strategic joint ventures, 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 debottlenecking opportunities. Financially, we expect to continue generating significant multiyear free cash flow and achieve our targeted leverage by 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. So 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 mentioned, please limit yourself to one question and one follow-up question, then return to the queue if you have additional questions. This will allow us to address the top questions from as many participants as possible in the available time this afternoon. Additionally, our Investor Relations team plans to be available throughout the week to address additional questions. Chino, we're now ready to open the call for questions.

All right. First question comes from the line Jeremy Tonet from JPMorgan. 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? And 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.

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, where 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 and providing customer service. We're actively engaging with extending contracts with customers. I'd say it's going certainly as well, but I would dare to say better than planned than we expected to continue to grow that position. Customers are excited about it. It offers more service, as we talked about, more connectivity and optionality. So, 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. And then kind of pivoting about 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? 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 of comments, and then I know Chris will talk specifically about the hydrogen opportunity. As we've articulated before, we've got a pretty broad asset base and the focus on emerging technologies is how do we integrate it with our existing assets, particularly around our areas of competency as well as our asset base. So, when we think about things, it's how do you connect it with the existing systems we have. Chris, can you cover the hydrogen piece?

Yes, 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. The concept here 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 Station 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. So, we're evaluating that particular opportunity in Ontario, but that technology can be applied everywhere. The Canadian government is 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.

Thanks. Good afternoon, everyone. So I wanted to ask first about volumes or production growth. Obviously, the public E&Ps seem to be 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. So just wanted to try to reconcile that. And 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 than December, January were somewhat soft, somewhat due to weather, somewhat due to slower completions. We've seen that cadence increase as you exit the first quarter and second. It's largely driven by private operators, integrated, but the independents are talking about total production profiles. So they are declining in other areas and growing in the Permian. The Permian, as a whole, is consistent, other basins are consistent with where we had them. But by and large, based on what we see across the basin, we're seeing line to slightly above, as Willie said. The producer mix is that's consistent with what we thought. We see roughly half the activity within the basin on dedicated acres that Willie was talking about. So 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. So there are some governors on growth, but so far so good. And we like always said we have a positive bias that 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.

And Michael, the only thing I would add is, as Jeremy talked about, you might pull some barrels in. The lag of additional activity is going to be back-end loaded, but the most important piece is momentum into 2023.

Got it. 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. So – thank you.

So Michael, we've included some extra information in the back based on the feedback we received. I'd like to have Jeremy Goebel go over two slides that I believe will provide you with insight into our perspective on the business, which may address your question. Jeremy?

Sure, Michael. If everybody can flip to Slide 27, it's just an overview of the assets. I think the first thing we see in general as we move NGLs west to east, we gather in the Fort Sask, which is near Edmonton on the far West. So 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 Cochran and we move that east for further fractionation at Sarnia. At Empress, which is the next dot over, we extract NGLs out and annual keyhole contracts and basically take the Y-grade NGLs in exchange for keeping whole on AECO gas, will fractionate some there and sell into local markets on that PPTC pipeline or will move further east to Sarnia for further fractionation in sale. So that's how it flows. When we talk about third-party business, a lot of that's around the Fort Sask in Windsor and St. Clair; those would be two of the bigger locations for third party. When we talk about Empress and part of that Cochrane Straddle, that's where we get the Y-grade that – on the keyhole contract. So, if you could then flip to Slide 30. If you look at Slide 30, this gives you a sense for the breakdown. So 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 barrels a day of straddle. Think of that as roughly 2/3 at Empress and 1/3 coming off the Cochrane plant. So that's the main driver. So that 65% associated with the Straddle, it's the keyhole construct, and then the rest is the fee-for-service business.

Michael, does that help?

Yes, very helpful. Thank you.

And there's some additional information there on Slide 31 that will give you kind of the hedge profile that we've had. It will allow folks to better understand our business.

Hi, I really appreciate the extra slides that you've added. I wanted to ask about Slide 16 with your takeaway chart. Can you kind of talk about what you mean by efficient operating capacity within 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. Certainly, if you go back in time and you look at the years around 2014, 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, so would you say that it's fair to consider people's concern about maintaining the current rates, specifically the target of 7 million barrels a day, in relation to production?

Well, what's shown is we haven't updated our guidance on production. It's still roughly 600,000 barrels a day per year, with an 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 I would think about this slide is that 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. This definitely allows us to participate in the volume growth. And the component of that is as the utilization increases, we would expect that the arbitrage, as the forward market implies, 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.

Yes, that makes sense. And I guess just as a follow-up on that, are you seeing any interest here from customers on blending and extending contracts? And I guess, similarly, are you interested here in blending and extending?

Jeremy, why don't you talk about?

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. So 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 a step to match what the current market looks like. We're not locking in the $0.40 tariffs for anything other than month-to-month. It's those $0.80 plus if you do maybe a year, and then you look to some that may step up to that $1.25 level. When we talk about blending and extending on some of our larger contracts, I think both us and the operator are very comfortable with us on the gathering side. We continue to extend those agreements to align for the longer term. So we're very comfortable that we'll have the volume on the system with 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 look to extend those when we're both aligned on that. But it's probably a next year thing than before it is today as they can make sure they get the space, and we can make sure we have a constructive dialogue around aligning on longer-term rates.

Thanks. That's really helpful. Thank you.

Thanks, Jean Ann.

Hi. Thank you. Just a 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 head up against that 90% or more, what do you expect that the rate should be?

Yes, Neil, this is Willie. We're showing this to emphasize that achieving a different tariff rate isn't as simple as reaching a specific point. Typically, as capacity increases and tightens, you’ll see a rise in rates before hitting the 90% mark. When considering what a tariff rate could be, it's really influenced by the cost of building a new pipeline. We anticipate that this cost will be higher than in the past, especially since the last round of pipelines was constructed in 2019. Moving forward, building new pipelines may face challenges due to potential supply chain issues, steel costs, and permitting hurdles, which could lead to an increase in the tariff fee. Jeremy, do you have any additional comments on this?

Yeah. No. I think Willie is correct in this assumption. It's going to be based on term, origin, and what other services are offered. So we'd prefer not to speculate on that, but the forward market is indicating something that's getting healthier and there's a more constructive dialogue between the carrier and the operator. The industry is comfortable with us, so we'll provide further guidance on longer-term rates as we get closer, if that's our view.

That’s perfect. Thanks for the color. And just as a follow-up, kind of close to the 900,000 barrels 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. The immediate benefits of a higher priced environment is process loss allowance. We have an increased higher price capture on that. That would be something that's very easy to quantify. The other pieces between blending, arbitrage, and contango storage really depend 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 capturing those opportunities. Jeremy, anything to add?

I'd say the other piece out of that is 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 and also have the tariff escalators. There's 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 are additional costs there. But having a smaller capital budget, where some of it is insulated, that's a competitive advantage. I agree completely with Willie, those are just a couple of supplemental ways that we do benefit from inflation or higher prices.

Got it. Thank you. Appreciate it.

Hi, good evening everyone. Maybe just a follow-up on a quick guidance question. The $75 million guidance raise. Just curious, is it really just relates to Permian crude gathering volumes in the NGL segment, with roughly no change, no long-haul in terms of just EBITDA contribution?

I'm going to let Al discuss that, but there's an aspect to consider. We successfully secured some additional long-haul, shorter-term contracts that contributed to our guidance number. The key point is to emphasize what I mentioned earlier; sometimes it's not a straightforward formula, but if the opportunities arise and they make sense for our various partners, we can include some short-term long-haul elements. You're correct that it's about volumes in NGL, volumes in crude, and the pricing impacts on both PLA and frac spreads. Al, would you like to add anything?

Yeah. No, you covered it. I think you summarized it. So the NGL's more commodity-based crude had positive PLA pricing, positive volumes, partially offset by just lower merchant opportunities primarily up in Canada.

Great. I appreciate the color. And then maybe just to dive a little deeper into the long-haul segment. It appears that you're receiving roughly 45,000 barrels per day of deficiency payments in your guidance for 2022. But it looks like we saw a 45,000 barrel per day upward revision in the long-haul volumes with the updated guidance. On the last call, you talked about anywhere from 1.5 years to two years for the Permian’s to kind of soak up those excess spot barrels and put the Wink-to-Webster ramp, et cetera. I was curious, just based off of the guidance update with matching that 45,000 to 45,000 for the 2022 guidance, whether that was potentially pulled forward so maybe a 1Q 2023 benefit where we could get above those MVC levels as it relates to Plains? Thanks.

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.

And so, as it relates to potential earnings inflection, is kind of cadence the same as the last call? Still middle of next year to end of next year based off of just the Permian production outlook in terms of getting above MVCs?

If I understand your question correctly, what we aim to demonstrate with Slide 16 is that, regardless of the minimum volume commitments, there are opportunities to capture additional volumes. Specifically, in our Permian gathering sector, we are capturing an additional 30,000 barrels a day compared to what we had in February, bringing our total to 280,000 barrels a day in the gathering system. This represents growth that we are attaining. There are also other opportunities that we will take advantage of as they arise. The main point I want to clarify is that people should not think that until the minimum volume commitments are filled, Plains cannot capture additional volumes. This is part of our guidance upgrade reflecting the extra volumes we have been able to secure. In the fourth quarter call, it was noted that if you consider it mathematically, there are additional minimum volume commitments coming online. If you were to theoretically match that with additional production volume, that would represent the expected number, but there are always chances to capture more barrels out there.

I think you hit that on the nail. I really appreciate the extra color on that. Have a great evening everyone.

Thanks.

Hi, guys. Just a lot going on this afternoon. So if you could just clarify again 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 the stronger performance that we're modeling in the company. Does that answer?

Perfect. Is the return of the insurance payments for this year, or will it extend into 2023?

No, we expect some of the collections will carry over into 2023. Therefore, our free cash flow will increase in 2023 due to the timing.

Okay. Thank you. It’s all I needed. Thank you.

Thanks, Becca.

Yes. Hi. Good afternoon, folks. And thanks for all the clarity. I just wanted to go back to Slide 30 again for a couple of seconds. So between the February guidance and your current guidance, between the three components of the pie chart, have you been able to hedge at better rates than you were heading in February, or is it just a view, because the unhedged prices have moved up, even 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 it. When we see prices spike, we might layer in some additional hedges. But coming into this year, the hedges – the most recent hedges are at higher rates, and we've had additional volume, as Willie said. Part of the outperformance is order flows from Western Canada to the Eastern markets have been higher. We extract additional NGLs, and that's all at the spot rates. Those sales will be this year or next year, in some combinations. 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.

And Sunil, just to make sure, the predominant amount of 2022 frac spreads are hedged.

Okay. And then kind of a follow-up to that. Is the market deep enough for you to hedge 2023 also, or is that mostly unhedged?

Sunil, this is Jeremy, again. We actively monitor. Think of it as a rolling program. We have an active 2023. Once again, we're opportunistic around when they do that. We'll provide further guidance as we get into 2023, but we manage it as an operation and manage earnings associated with it. We're trying to capture higher levels as well. We'll continue to update you on that, but there is a deep enough market. It's very thin in 2024, but 2023 is pretty active.

Got it. And then lastly, could you remind us on the process loss allowance? How much is typically the bps you get on the volumes that you move as PLA, or is there any other good way to think about margin sensitivity?

It's substantial – it’s 2 million to 3 million barrels a year associated with PLA depending upon operating performance, and we continue to optimize around that. So it's a big footprint. That's predominantly in the US where we do collect that, but it's substantial.

Got it. Thanks. Thanks for that.

Thanks, Sunil.

And there are no further questions in the queue. I will now turn the call over back to the presenters.

Yeah. So 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 the feedback. We've had many discussions with folks. As always, we're trying to further improve our disclosure and transparency and how we run the business. I do know that, as we've changed our segments, there's an opportunity to continue to make improvements. So I 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.