Hello, and thank you for standing by. Welcome to the PAA and PAGP third quarter 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 one on your telephone. You'll hear an automatic message advising you that your hand is raised. Please be advised that today's conference is being recorded. I'd like to hand the conference over to your speaker, Roy Lamoreaux, Vice President, Investor Relations, Communications and Government Relations. Thank you, Therese. Good afternoon, and welcome to Plains All American's third quarter 2022 earnings call. Today's slide presentation is posted on the investor relations website under the news and events section at plainsallamerican.com, where an audio replay will also be available following today's call. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on slide two. An overview of today's call is provided on slide three. A condensed consolidated balance sheet for PAGP and other reference materials are located in the appendix. Today's call will be hosted by Willie Chiang, Chairman and Chief Executive Officer, and Al Swanson, Executive Vice President and Chief Financial Officer. Other members of our team will be available for Q&A, including Harry Pefanis, our President, Chris Chandler, 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 will now turn the call over to Willie Chiang. Thank you, Roy, and thank you everyone for joining us this afternoon. Today, we announce strong third quarter results above our expectations, reflecting continued execution of our long-term goals and initiatives, and our strong performance in both of our crude oil and NGL segments. In summary, third quarter adjusted EBITDA attributable to PAA was $623 million. We increased our full year 2022 adjusted EBITDA guidance by $75 million - $2.45 billion, which is $250 million above our initial February guidance. The year-to-year increase is driven by outperformance in both our crude oil and NGL segments due to the capture of additional volumes, higher commodity prices, and favorable margin-based opportunities. Additionally, today we announced and closed an $85 million acquisition of an additional 5% in the Cactus II pipeline, bringing our total ownership to 70%. Importantly, we ended the quarter with a leverage of 3.7x and expect to end the year at 3.8x, both below the midpoint of our targeted leverage range. This supports increasing returns of capital to our equity holders. As such, within today's earnings release, we laid out a multi-year capital allocation and financial framework, which I will discuss shortly. Before that, I wanted to reiterate our views on why we remain constructive on long-term industry fundamentals. Notwithstanding global economic uncertainty and continued volatility in the commodity markets, we continue to expect global energy supply and demand to remain tight. As shown on slide four for the past number of years and for a number of reasons, there's been a lower level of investment in the upstream sector reducing resource development. At the same time, energy demand continues to grow, while historical supply buffers in the form of OPEC plus spare capacity and global inventories are greatly reduced and have been further impacted by recent geopolitical events. Year to date, we have seen U.S. strategic petroleum reserve draws of approximately 190 million bbl and commercial inventories remain low or at below historic levels over the same timeframe. Global markets remain tight and the world needs short cycle North American production growth. As summarized on slide five, we've made meaningful progress on our long-term goals and initiatives, and as such, 2022 is a positive inflection point for Plains. For the last several years, we have focused on de-leveraging by maximizing free cash flow and reducing absolute debt. The success of this effort, when combined with solid operating, commercial, and financial performance, enabled us to achieve our leverage objectives well ahead of our initial expectations and to accelerate returns to equity holders while providing greater clarity on our multi-year capital allocation framework. As described in our press release this afternoon, we provided updates to our capital allocation and financial framework as follows. We currently intend to recommend to the board a $0.20 per unit annualized increase of our quarterly distribution payable in February 2023. Beyond 2023, as part of our annual budget review process with the board, we anticipate targeting annualized distribution increases of approximately $0.15 per unit each year until reaching a targeted common unit distribution coverage ratio of approximately 160%. We anticipate leverage migrating below the low end of our targeted range of 3.75x-4.25x in 2023, and consistent with our objective in achieving and maintaining our mid-BBB and equivalent credit ratings. Additionally, opportunistic unit repurchases will remain a component of our capital allocation framework, which will be a dynamic assessment of business outlook, market environment, and capital allocation options. As we look forward, we remain focused on driving shareholder value and improving the resilience of our earnings by leveraging our existing crude oil and NGLs infrastructure. This includes capital-efficient brownfield expansions and debottlenecking opportunities underpinned by contractual commitments. Potential bolt-on acquisitions, such as the Advantage JV and the acquisition of additional interest in Cactus II, and the optimization and alignment of existing assets with emerging energy opportunities. In Canada, we recently completed a win-win non-cash transaction to gain full ownership of our existing Empress facilities in exchange for a long-term processing capacity lease at the facility, allowing us to further optimize and operate the assets more efficiently over time. Additionally, we continue to evaluate capital-efficient debottlenecking and expansion projects around our four Saskatchewan facilities and hope to be able to share additional details over the next coming quarters. With that, I will turn the call over to Al. Thanks, Willie. We reported third quarter adjusted EBITDA of $623 million, which includes the benefit of increased volumes across our systems, primarily within the Permian, higher commodity prices, as well as Canadian margin-based opportunities. Slide 17 and 18 in today's appendix contain quarter-over-quarter and year-over-year segment adjusted EBITDA walks, which provide more detail on our third quarter performance. A summary of our progress on our goals, key financial and operating metrics, and 2022 guidance is located on slides six through nine. We've increased our full year 2022 adjusted EBITDA guidance by $75 million to ±$2.45 billion, primarily driven by our strong third quarter performance. Slide six shows our key 2022 financial metrics and reflects strong distribution coverage of 265% and free cash flow after distributions of $670 million, which provides ample capacity supporting our multi-year capital allocation framework. I would note that we have left our asset sale target at $200 million, but as a result of current volatility in capital markets, the remaining $140 million that hasn't closed could shift into the first half of 2023. Additionally, going forward, Cactus II will be consolidated into PAA's future financial statements. Similar to the Permian JV, volumes will be reported on a consolidated basis and earnings on a proportional basis. Before providing more detail on today's capital allocation announcement, I wanted to share a few directional comments on 2023 with formal guidance to come early next year. We continue to expect growth in our crude oil business, primarily driven by our Permian operating leverage and improving margins on short-term contracted long-haul opportunities. For our NGL segment, we currently anticipate lower C3+ spec sales volumes due to third-party facility turnaround and absent of 2022 weather benefits. Furthermore, current forward markets indicate lower year-over-year frac spreads. The combination of these could lower 2023 NGL segment adjusted EBITDA by roughly $100 million versus 2022 guidance. In regard to capital allocation, our proposed long-term capital allocation framework and financial strategy are summarized on slides 10 through 13. We are focused on generating meaningful multi-year free cash flow and improving shareholder returns by increasing returns of capital to equity holders, making disciplined, accretive investments, and ensuring balance sheet flexibility. With respect to increasing returns of capital to our equity holders in a long-term sustainable manner, as shown on slide 11 and detailed in our earnings press release, we intend to recommend to our board an annualized increase of $0.20 per common unit for our quarterly distribution to be paid in February, which is one quarter earlier than we would normally implement a change to our quarterly distribution. Beyond 2023, we will continue to evaluate our capital allocation program, financial positioning, investment opportunities, and business outlook with our board of directors as part of our annual budgeting process. Subject to that process, we currently anticipate targeting annualized distribution increases of $0.15 per unit per year until reaching a targeted common unit distribution coverage ratio of approximately 160%. Upon reaching our target coverage, subsequent distribution increases will be driven by future DCF growth and evaluated as part of our annual budgeting process. Opportunistic equity repurchases will remain a component of our long-term capital allocation program. Since the inception of the program, we have repurchased $300 million of our $500 million authorization, or approximately 4% of our common units outstanding. With respect to capital investments going forward, as summarized on slide 12, we will continue our disciplined approach, focusing on high return expansion and debottlenecking opportunities that leverage our existing crude oil and NGL infrastructure. Longer term, we continue to expect to self-fund annual routine investment capital through our excess cash flow and coverage. Regarding our balance sheet, as described on slide 13, we have achieved our leverage goals and anticipate migrating leverage below the low end of our target range of 3.75-4.25x in 2023. We will take a prudent long-term approach, focusing on increasing cash return to equity holders while maintaining and improving financial flexibility, consistent with our objective of achieving and maintaining a mid-BBB equivalent rating. Before I turn the call back to Willie, I wanted to provide a brief update on potential changes to the pricing of our Series A and Series B preferred equity securities. The Series A security issued in 2016 currently has a yield of 8% and contains a one-time option for holders to reprice the security based on the 10-year U.S. Treasury rate + 5.85%. The holders will have the opportunity to reprice the security during a 30-day period beginning in late January 2023. If the right is exercised, we would anticipate the yield increasing to approximately 10% based on current treasury rates. After repricing, we will obtain a call right at 110% of par. Series B security issued in 2017 has a fixed yield of 6.125% for the first five years, shifting to floating on November 15, 2022, at a new rate of three month LIBOR plus 4.11%. Upon the shift to floating, the security becomes callable at 100% of par. If both were to reprice at current market conditions, total annual preferred dividends would increase by approximately $55 million a year to approximately $255 million per year. Even with the potential increase, we still have ample financial flexibility to continue lowering leverage and increasing returns of capital to common equity holders in a manner consistent with what we have described on today's call. With that, I will turn the call back to Willie. Thanks, Al. Today's results reflect another solid quarter of performance and execution. Although we're monitoring current macro and geopolitical events, we believe long-term fundamentals remain constructive and that our business will continue to perform well in the current and the longer-term environment. We've made steady progress reducing leverage and creating additional financial flexibility, which has positioned us to provide additional clarity on our multi-year capital allocation framework. We will continue to take a long-term disciplined approach to our business and the execution of our capital allocation priorities. We appreciate your continued interest and support, and we look forward to providing further updates along with our formal 2023 guidance on our earnings call in February. Summary of the key takeaways from today's call is provided on slide 14. With that, I'll turn the call over to Roy to lead us through Q&A. Thanks, Willie. As we enter the Q&A session, please limit yourself to one question and one follow-up question, then return to the queue if you have additional follow-ups. This will allow us to address the top questions for as many of our 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. Therese, we're now ready to open the call for questions. Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. Please stand by while we compile the Q&A roster. Our first question is from Michael Blum from Wells Fargo. Michael? Thanks. Good afternoon, everyone. You know, maybe you start with the distribution growth announcement here. It seems like it really tilted the scales towards distribution growth over buyback. I'm wondering if you could just kind of talk through, you know, the thought process there. Sure Michael thanks for the question. We have, and the reason for that is, as we think about our capital allocation process, you know, it's a pretty dynamic matrix that we look at with a number of things. The goal is to really help improve the value of the company and the ability to be able to have additional cash flow which we can distribute back to unitholders. As we think about that, we think the distribution is the most efficient way to do that as far as returns getting returns back to giving back to unitholders versus buybacks. It's really for that reason and the progress that we've made so far that we've articulated this multi-year strategy. Got it. Thanks for that. I also just wanted to ask about premium growth. I would love to get your latest thoughts on where things are trending, you know both for this year and into 2023. I'm sure you saw some of the comments from some of the majors on perhaps a slight slowdown. Wanted to kind of get your lay of the land. Thanks. Well Michael let me. I'll give you some comments. We are gonna wait till February 2023 to give detailed guidance. Where it stands right now is it's really in lockstep with what we've expected. year-end-to-year-end growth in 2022 is gonna be roughly 650,000 bbl a day. You know, we've premised roughly a 10% increase in rigs running about 150-160 rigs next year. That's what we'll have to kind of validate as we go through the next number of months in talking to the producers. I will highlight that with that growth, if you take a look at the market capture of our volumes, we've been very successful in being able to capture volumes into our gathering joint venture, which ultimately feeds the rest of the business. Great. Thanks. Thanks, Willie. Thanks, Michael. Thank you, Michael. Our next question will be coming from Keith Stanley with Wolfe Research. Mr. Stanley? Hi. Thank you. I guess sticking with the distribution, can you explain a little more how you came to the 160% minimum coverage threshold using DCF for future dividend growth? I also, you know wanted to ask. You talked about the preferreds going to variable rates, which is, you know a pretty expensive source of capital. How did you balance what's a very robust dividend growth plan against you know alternative uses like trying to pay down that preferred equity? Yeah, Keith Mr. Stanley, let me take that, and I'll let Al talk about the preferreds. Hey, on the 160% coverage, what we're driving for there is, as you know, we're funding CapEx from cash flow. As we put this multi-year trajectory out on the increase, the 160% target is really kind of of a governor to make sure that we've got adequate coverage and cash flow to be able to cover our routine CapEx expectations, our annual program, as well as a little bit of extra dry powder to be able to further take our leverage down and be prepared for anything that might present itself. The $160 is really to make sure that we're conservative in funding our CapEx in the future going forward. Al, you wanna take the preferreds? Yeah, I'll take a shot at the preferreds. Between the two, the one, you know, if it was repriced today, would be about 10%. We view that right now on a 50/50 basis in how the equity component of that. It's less than our cost of capital today. We trade at, what? A DCF yield of probably 18%. Ten-year money today is probably 7%. 50/50 would be 13.5%. While it's more expensive, it's still not more expensive when you look at the components of it relative to our cost of capital. We're too new into just having hit and got to our leverage objective to use a deleveraging or a leveraging, excuse me, i.e., go use debt to take that out in the near term. Clearly, our objective that you heard in our comments is to continue to move leverage down. At some point, we may have the capacity to deal with that, but today we don't believe that would be prudent to use a leveraging transaction to try to reduce that cost. It's actually pretty manageable relative to what the current capital markets are providing, and we surely don't wanna use equity, common equity to try to take it out at this point. All of that could be on the table a year or two down the road. The important thing is we do see call options coming our way with this. We do control our destiny a little bit when we get into a position to be able to deal with this. Got it. Thanks. If I could just clarify, second question on your expectation to be below the low end of the leverage range in 2023, and you gave some puts and takes on next year. Is that assuming that you continue to repay debt with some of your free cash flow through 2023? Yeah. Our intent, you know, again, if you think of what we are mentioning with the distribution, and being capital disciplined on investments, we will still have very strong cash flow after distributions, and our intent will be to continue to reduce debt. We do, when we look into the future, believe we'll have cash flow growth as well. Bottom line is we do expect to continue to pay down debt and reduce debt and increase the flexibility. We don't wanna get to the point of setting a new range now. We intend to migrate below and then operate there for a while, and we can reevaluate that in the future. Thank you. Thank you. Our next question comes from Brian Reynolds of UBS. Brian, your line is open. Hi, good afternoon. Maybe just to quickly follow up on some of the capital allocation questions. You got $2.2 billion in preferreds that can convert next year, but you also have the $1.1 billion in long-term debt that can be refinanced in 2023. Kind of just curious, as you enter the year, like what are your priorities just given the equity credit for the preferreds? Is it your priority to refinance that debt? I guess kind of a follow-up question, can you just remind us of your liquidity, particularly if you know the cash plus the revolver and your ability to use that, you know, to manage, you know, potentially, a reduction in rates call a year from now? Thanks. Brian, this is Al. You know, as of the end of September, we had $3.3 billion of liquidity, which included $600 million of cash on the balance sheet. The cash is earning more than the first note that matures early next year, or we would have taken it out before end of the year. It became where we could take it out at par here just yesterday, but we'll take it out next year. Our intent would be to take and retire the $1.1 billion next year and not access the market. That'll be part of our deleveraging. We would fully expect the preferreds to remain out. Again, you know while the rates are going up and obviously we don't know where the Fed will stop, so that the one that floats may become an issue, but we would not intend to be looking at retiring those next year. Great. Thanks for the clarification. Maybe just a simple operational question. It seems like, you know, PADD 2 movements were a little noisy, you know, particularly with some, you know refinery movements. Just kinda curious if you can talk about. Those intrabasin volumes during the quarter, and if that's a trend that could continue into 2023 or if you think that's more of a you know singular event for the quarter? Thanks. Hey, Jeremy, why don't you take that one? Hey, Brian, this is Jeremy. The PADD 2 movements, low inventories at Cushing, and you haven't seen a ton of growth in the Rockies, and you've even seen some facilities offline in Canada, which yields higher movements up basin with the crack spreads you're seeing specifically on the diesel side. We would expect that to continue as long as refining runs and refining demand remains strong. That we would expect to continue. The intrabasin movements are a function of production growth in the Permian Basin, and you can almost look at it as the gathering volumes grow and the intrabasin volumes grow accordingly. We would expect that to continue as well. Brian, this is Willie Chiang. Go ahead, Willie Chiang. Just reinforcing a point that we always like to talk about. When you think about our system, there's a lot of flexibility and access to multiple markets. I'll just remind you that barrels could be going to the coast, but if the markets are such that they wanna go to Cushing, we have the capability to do that. That's kind of the benefit of flexibility. Great. Fair enough. I'll jump back in the queue. I appreciate the color. Thanks, Brian. Thank you. Our next question is from Jeremy Tonet of J.P. Morgan Securities. Hi, Jeremy. This is Jeremy. Good afternoon. I just want to dive in real quick here, a little bit more on the guidance. I think for crude oil, it's $18.90 in August, and it was $19.55 now. Just wondering if you could provide a bit more color on what changed between August and now to drive that uptick. Yeah. The majority of it is third quarter performance and some of the margin opportunities we've seen primarily up in Canada were likely the bulk of it. We also seeing some just kinda temporary spot movements on our assets, but the margin opportunities were the majority of it. Got it. Thanks. Pivoting over to Cactus. Just wondering if you could provide some color with regards to acquisition multiple or accretion expected. Just trying to see how that, you know, fits in there versus other opportunities. Jeremy, let me take this one. That was a win-win deal. It was a good deal for everybody. The way we look at this is Western was interested in selling. It was a negotiated deal. It allows now both Enbridge and us. It allows us to strengthen our relationship. I think the way it's set up is if you think about our assets, we're stronger on the gathering side. If you think about Enbridge, they're stronger on the downstream side. It really fits as far as integration. Our expectation is that the joint venture will be able to extract some more synergies and additional volumes as we go forward. I'll probably leave it at that and not get into multiples discussion. Got it. I'll leave it there. Thank you. Thank you. Thank you. Our next question is from Jean Ann Salisbury from Bernstein. Jean? Hi. I just want to make sure I understand what's driving the Crude pipeline EBITDA this year. On slide 17, you have a helpful bridge of the Crude segment versus last quarter and kind of call out both increased volumes and then also MVC payments. Is that mean that people are effectively paying you MVCs on pipelines that don't go to the U.S. Gulf Coast from the Permian, but then you're over your MVC level and getting spot rates on the pipelines that are going to the Gulf Coast? Is that, like, a sustainable setup? Jean, this is Jeremy. Yes, we are receiving some MVCs, but we're also replacing with some incentive tariff. We expect that to go away as the shippers start to ship to their MVC levels, which we fully expect that to happen shortly. I'd say that has been temporary as the spreads have been thin, but as the spreads widen, you would expect that to be different. The Cushing, that's not on MVC. There are some component that is. From a recontracting standpoint, we continue to add more on a term basis across both the Cushing corridor as well as the corridor to Corpus. There's plenty of demand for capacity to the coast at increasing levels. Got it. That makes sense. I was just wondering if there's been any update on the Fort Saskatchewan expansion. Should we be assuming any CapEx for that in 2023? Yeah, we're still developing the project Jean and we don't have anything specific to talk about. I would leave that to our hopefully in February our February call, we'll have a little more info on that. We'll share it at that point. Okay. Sounds good. Thank you. Thank you. Thank you, Jean. Our next question is from Neel Mitra from Bank of America. Neel? Hi Good afternoon, guys. Just wanted to look at the distribution in light of your commodity and volumetric exposure. Obviously you benefit this year from the frac spread in Canada and your gathering rate has some volumetric exposure as well. Are you looking to term up some of the long-haul pipelines to be able to maintain that fixed increase every year? How are you looking at that exposure? Well, we're absolutely looking at how do you firm up additional volumes. I made a comment earlier about taking some of the volatility out and getting kind of fixed volumes. We're working on that every single day. I don't know if I get a specific question in areas there. I was just asking kind of how are you looking at all kind of the commodity exposure when you evaluated the fixed distribution increase? Are you comfortable with a certain run rate with the Canadian assets or just volumetric growth in the Permian? Oh, I got your question. Maybe if you take a look at nine, if I understand your question, you know, when we think about the higher prices, it definitely benefits us, primarily in PAA, in crack spreads. If you look at where we started the year at, we had a more modest expectations of crude oil environment, roughly $75. For the year, we're probably gonna average close to $95. There's a piece of that that is related to oil price. We think as we go forward, we're gonna be able to capture some of that, and that's all been factored in as we think about our distribution coverage going forward. Got it. Then my second question is in regards to Cactus I and II and your Corpus Christi exposure. You've had record exports out of the Gulf Coast for two quarters in a row. Corpus Christi disproportionately benefited. I was wondering how sustainable you think that growth is going to Corpus Christi in light of the exports. Then the second part of that would be how should we think about the MVC impact of the second round of minimum volume commitments from Wink to Webster? Jeremy, you wanna take that one? Sure. On the Corpus Christi export, the continued expansion of the Tidewater channels, which will benefit all of the docks. There's plenty of capacity to export. The pipelines are filling up, but the rates are going up for the marginal capacity, which benefits the pipeline owners, the dock owners. There's substantial expansion capacity to expand. Right now, it's got the best logistics and the highest price, which is why there's twice as many exports out of there as any other port. There's use for exports across the Gulf Coast, but Corpus Christi would expect to continue to receive a significant portion of those. I think that answers your first question. The second one on, was it minimum volume commitments? It was on Wink to Webster. On Wink to Webster. Impact is consistent with what we said in February. They ramped in February of next year, and production growth this year has absorbed those MVCs from this year, and next year we would expect the same thing. Growth is on pace with where we thought. There might be some bumps due to natural gas takeaway or others, but longer term, we fully expect that to take place. The larger impact from there is felt in Houston as you have Wink to Webster shippers moving their lease book back to Midland. It doesn't necessarily impact the barrels that are for export because that's all priced into the forward discount differential, and it will all be priced into our guidance. We fully expect to be full to the coast on our pipelines next year. For the margins to heal over time, you'll need some of those MVCs to be absorbed by production growth. You there, Neel? Yes, I am. Thanks. Did that answer your question? It did. I appreciate it. I mean, fundamentally, our view is global demand is gonna continue for crude oil. If you think about the export and the sources of that, we think it's coming from North America. We think it's a pretty constructive environment for exports from the U.S. Got it. Got it. Thank you, Neel. Our next question is coming from Michael Cusimano from Pickering Energy Partners. Please go ahead. Hey, good afternoon, everyone. Hi, Michael. Just wanted to go back to a comment you made earlier on year-over-year crude growth. Yes. Just first, can you elaborate if you were specifically talking about volumes or EBITDA or both? I'm sorry. The numbers I was giving you were volumes from year end to year end, 2022 to 2023, of roughly 650,000 bbl a day. Just to make sure I communicated effectively, when we talked about checking 2023, the rig count, the horizontal rig count in the Permian, our assumption was roughly 350-360 rigs. We're running about 330 right now. Okay. I think I might have missed it, but maybe I thought you made a comment about growing the crude segment in 2023. I was curious if that was explicitly about volumes or earnings. No, I didn't give you any guidance on overall crude volumes. Jeremy, did you have something you wanted to add to that? Yeah. I think his comment in the script, or I think it was from Al actually, was that we would expect year-over-year growth. If you remember, our gathering system benefits from production growth in the field. I think it was just a comment to say the same type of growth we saw this year, we would expect to see that on the gathering side with some incremental growth due to increased volumes and increased margins on the long-haul business as well as the step up in MVCs on the Wink to Webster project. I think that was the comment. Okay. I guess, as my follow-on, do you think the growth that you would expect would outweigh any, maybe like conservatism on the price deck that you would assume from you know any Pipeline Loss Allowance uplift or things like that? Hey, Michael, this is Jeremy. We were just trying to give some directional indication of the impact of frac spreads since it's been so significant. The intent was not to provide guidance for next year. We'll update everybody on guidance for the crude oil the NGL business in February. The other piece on that we wanted to give you a heads up on is there's some planned outages that you probably wouldn't have insight into. We wanted to give a heads up that there will be an impact on that as well so. On the NGL business. Got it. On the NGL business, is the downtime related to the smaller expansion that you had mentioned last quarter? If so, what's the timing look like for when that's completed or resolved? Yeah, I'm not gonna give you specifics on it only because it's a third-party supplier. It's a third-party straddle plant that impacts our Fort Saskatchewan business, so I'll hold off on that. It is independent. All right. Of the project that you referenced. Okay. Understood. Got it. That's all for me. I appreciate the help. Thank you very much. Our final question comes from Sunil Sibal from Seaport Global. Hi, Sunil. Yes. Hi. Hi, good afternoon, everybody. Staying on the NGL segment, could you give us a sense of, you know, how much of your NGL exposure for 2023 is hedged at this point in time? Sunil, we're not gonna share that at this point. We'll share more in February. All right. If I look at the metrics that you laid out on slide six with regard to the, you know, 2022 guidance update. It seems like, you know, adjusted EBITDA is moving up by $75 million. However, the implied DCF to common is flat versus your August guidance. I was just curious, you know, what's the difference that keeps the DCF flat? Yeah. This is Al. I'll take a shot at it. One, Canadian taxes. Two, some of the timing around distributions and earnings on being different on unconsolidated entities, as well as on our non-controlling interests, distributions to non-controlling interests. Then the last one is just we probably should have rounded down last quarter. We've been trying to keep those numbers kind of round. No one thing a number of different things. Good question. Your free cash flow is still going up. You kind of recoup some of all these factors when you look at the free cash flow? Correct. Oh, okay. Thanks for that. Thanks, Sunil. Thank you, Sunil. At this time, I'd like to turn it back over to the company for their closing remarks. Great. Thanks, Therese. Thanks everyone for joining us and for your questions and your interest in our company. We'll look forward to giving you updates. Have a nice evening. Good day. You may now disconnect. Have a good evening.