Greetings, and welcome to the Magellan Midstream Partners third quarter earnings call. During the presentation, all participants will be in a listen-only mode. Afterwards, we will conduct a question-and-answer session. If you have a question, please press the one followed by the four on your telephone. If at any time during the conference you need to reach an Operator, please press star zero. As a reminder, this conference is being recorded Thursday, October 27th, 2022. I would now like to turn the conference over to Aaron Milford, CEO. Please go ahead. Hello, and thank you for joining us today to discuss Magellan's third quarter financial results. Before getting started, we must remind you that management will be making forward-looking statements as defined by the Securities and Exchange Commission. Such statements are based on our current judgments regarding the factors that could impact the future performance of Magellan, but actual outcomes could be materially different. You should review the risk factors and other information discussed in our filings with the SEC and form your own opinions about Magellan's future performance. As you saw this morning, we reported third quarter results that beat our EPU guidance, continuing our trend of solid financial performance so far this year. Most notably, our refined products transportation revenues exceeded our expectations, primarily due to higher average tariff rates, and our commodity margin benefited in part from the basis differential that flipped positive briefly just as the gas liquids blending season began at the end of the quarter. There were a number of other favorable items, including overall lower expenses, that led to our outperformance. In addition, we announced a $0.01 increase to our quarterly cash distribution last week, consistent with our guidance and general approach from last year. At current yield of over 8%, our yield remains attractive, and we recognize that distribution growth is important to a portion of our investors. Magellan is proud to continue our trend of increasing the payout to investors each year. I'll now turn the call over to our CFO, Jeff Holman, to briefly review our third quarter financial results versus the year ago period. Then I'll be back to discuss guidance for the remainder of the year before answering your questions. Thanks, Aaron. First, I'll note that as usual, I'll be making references to certain non-GAAP financial metrics, including operating margin, distributable cash flow, or DCF, and free cash flow. We've included exhibits to our earnings release that reconcile these metrics to their nearest GAAP measures. This morning, we reported third quarter net income of $330 million compared to $237 million in third quarter of 2021. Adjusted earnings per unit for the quarter, which excludes the impact of commodity-related mark-to-market adjustments, was $1.29, which, as Aaron pointed out, exceeded our guidance of $1.15. DCF for the quarter increased to $290 million, up $13 million from last year. Free cash flow for the quarter was $273 million, resulting in free cash flow after distributions of $59 million. A detailed description of quarter-over-quarter variances is available in the earnings release. As usual, I'm just going to touch on a few highlights. Starting with refined products, operating margin of $384 million was 40% higher than the 2021 period, driven primarily by a more favorable commodity environment as well as higher average tariff rates. Total refined products volumes were slightly lower between periods, but the increase in the average transportation rate more than offset this modest volume decline. The higher average rate was driven primarily by the mid-year 2022 increase in our tariffs of about 6% on average. Just as a reminder, this 6% average increase consisted of an 8.7% increase in the 30% of our markets with index rates and an average increase of approximately 5% in our markets deemed workably competitive. In addition, rates in the current period benefited from more long-haul shipments, which move at higher rates. The increase in long-haul shipments was driven in part by our customers using the extensive connectivity of our system to satisfy market demand in areas along our network that were impacted by refinery disruptions during the quarter. Operating expenses for the refined segment decreased during the third quarter of 2022, primarily due to favorable product overages, which reduce operating expense. You may recall that we discussed product overages last quarter as an unfavorable item, and as we mentioned then, they can fluctuate period to period with the operation of the pipeline. We generally expect these variances to more or less even out over time as we've recently experienced. Product margin increased between periods, in part due to higher margins and volumes on our gas liquids blending activities. Our realized blending margins increased year-over-year to about $0.75 per gallon versus closer to $0.40 per gallon in the prior year period. On our last couple of calls, you've heard us talk about how basis differentials between the Mid-Continent and New York Harbor have been wider than normal, negatively impacting the margins we earn on our blending activities. More recently, we saw that basis move in the other direction, resulting in a benefit to our realized margins as we kicked off the fall blending season before widening again of late. In addition to favorable gas liquids blending results, we have significant unrealized gains on futures contracts related to our hedging activities, which favorably impacted operating margin in the current period. Of course, we ignore these out-of-period gains on futures contracts in our calculations of DCF for the period to better match their DCF impact with the underlying product sales activity that will occur in future periods. Turning to our crude oil business, third quarter operating margin increased to $127 million, nearly 14% higher than in the 2021 period. Longhorn volumes averaged 225,000 barrels per day compared to around 240,000 in the third quarter of 2021, primarily due to lower committed shipments based on the timing of when our customers have elected to move volumes under their commitments. Volumes in our Houston distribution system increased versus the prior year period, with more tariff shipments resulting from a recent pipeline connection to our system. In addition, terminal throughput fees increased as a result of more customers electing to move barrels under a simplified pricing structure for our services within the Houston area. Similarly to last quarter, storage revenue declined due to lower utilization and rates as we continued to see general softness in storage demand due to prolonged market backwardation. Crude oil product margin benefited from additional crude oil marketing activities in the current period, as well as unrealized gains on futures contracts related to our hedging activities. Moving on to our crude oil joint ventures. BridgeTex volumes were approximately 250,000 barrels per day in the third quarter of 2022, down from just over 315,000 barrels per day in 2021, primarily due again to the timing of when our committed shippers have elected to move volumes under their commitments. While Saddlehorn volumes averaged a little more than 215,000 barrels per day, basically in line with the 2021 period. From an equity earnings perspective, we once again recognized additional deficiency revenue for both the BridgeTex and Double Eagle pipelines, which offset lower average rates on Saddlehorn, resulting in essentially flat equity earnings for the segment. It's important to note that although this recognition of deficiency revenue at our joint ventures results in higher equity earnings, the associated cash payments were already received from customers in prior periods, and our proportionate share of those payments were distributed to us by our joint ventures and recognized by us as DCF at that time. Moving beyond the individual segments, there are just a few other items I'd like to highlight from our year-over-year results. G&A expense increased between periods, primarily due to higher overall compensation costs, due in part to an increase in incentive comp, reflecting our strong results year-to-date. In addition, some miscellaneous non-comp related items, including elevated legal and technology costs, contributed to the year-over-year increase. Other expense was unfavorable, primarily due to additional expense recognized during the quarter associated with ongoing legal matters previously disclosed in our SEC filings. Finally, as everyone is aware, we sold our independent terminals in June, which of course resulted in lower income from discontinued operations. Moving on to capital allocation, balance sheet metrics, and liquidity. First, in terms of liquidity, we continue to have our $1 billion credit facility available to us through mid-2024. As of September 30, the face value of our long-term debt was still about $5 billion, with $29 million of commercial paper outstanding. The weighted average interest rate on our debt remains about 4.4%, with our next bond maturity in 2025. Our leverage ratio at the end of the quarter was 3.3x for compliance purposes, which incorporates the gain we realized on the sale of our independent terminals. Excluding that gain, leverage would have been about 3.7x. As for capital allocation, as you've heard us say before, we remain committed to maintaining the financial discipline we are known for while delivering long-term value for our investors through a combination of capital investments, cash distributions, and equity repurchases. We continued to execute on our buyback strategy during the quarter, repurchasing 2.7 million units at an average price of about $50 per unit for a total spend of nearly $130 million. Year- to- date, we have spent $377 million on unit repurchases, bringing the total since inception to a little under $1.2 billion. So far in 2022, we have returned a total of over $1 billion to our investors through a combination of unit repurchases and cash distributions. Including our recently announced distribution, which pays out next month, that number will be over $1.2 billion. We continue to see unit repurchases as an important focus of our ongoing capital allocation efforts, and we continue to expect free cash flow after distributions to generally be used to repurchase our equity. As we are always careful to note, the timing, price, and volume of any unit repurchases will depend on a number of factors, including expected expansion capital spending, available free cash flow, balance sheet metrics, legal and regulatory requirements, as well as market conditions and the trading price of our equity. Of course, we remain committed to our long-standing four times leverage limit. With that, I'll turn the call back over to Aaron. Thank you, Jeff. Based on our results and our expectations for the rest of the year, we are increasing our annual DCF guidance by $10 million to $1.1 billion. While we were pleased with Magellan's performance so far this year, you may have noticed that our new annual guidance did not increase by the full amount of our outperformance during the third quarter. Like last quarter, we continue to keep our eye on a number of factors, including the volatile commodity environment as well as economic conditions generally. They have led us to remain somewhat conservative in our expectations for the remainder of the year. Specific to our commodity activities, we've continued to lock in additional hedges over the past few months related to gas liquids blending. With 90% of our fall blending currently hedged at margins in excess of $0.50 per gallon. All in, we now expect blending margins for the full year 2022 to average around $0.45 per gallon, which is a bit higher than our previous estimate and consistent with our five-year average blending margin. The primary reason for the annual increase is related to the short-term improvement in the basis differential Jeff just discussed. We'll be paying close attention to further moves in this basis differential as we finish up the year and look ahead to next year. We've also continued to make significant progress in hedging next year's blending, with 50% of our expected 2023 blending now hedged at an average margin of $0.65 per gallon. Broken down further, we have 70% of spring 2023 activity hedged at margins of $0.75 per gallon, and have even started to hedge fall 2023 activity with about 25% hedged at $0.55 so far. This is a bit earlier than usual to hedge out that far, but margins are attractive, so we're locking in prices to the extent there's opportunity and depth in the market to do so. Moving on to expansion capital. We now expect to spend approximately $90 million in 2022, with $100 million in 2023 and $40 million in 2024 on expansion projects that have already been committed. The increased estimates primarily relate to the recently announced $125 million expansion of our Texas refined products pipeline system from Houston to El Paso, which is supported by take-or-pay commitments from quality counterparties. Based on our current construction schedule, we expect the expanded capacity to be available in early 2024. As usual, we continue to assess new opportunities for infrastructure projects with attractive risk and return profiles. Most recently, we've estimated that around $100 million of expansion capital per year is a reasonable assumption for unfunded projects as we continuously analyze and develop value-creating projects. As we have mentioned in the past, this $100 million estimate is just that, an estimate, with some years possibly a little higher, other years possibly below. We don't foresee a material shift to significantly higher organic growth spending levels at this time. Since we're already planning to spend $100 million next year for currently committed projects, it is likely our expansion spending will ultimately be above that level in 2023 as we bring additional projects across the finish line. Consistent with our usual approach, we plan to provide overall financial guidance as well as key assumptions specific to 2023 when we report fourth quarter financial results early next year. In the meantime, however, I'll end my prepared remarks today by briefly noting a couple of recent positive developments in our crude oil business. In particular, we're pleased to receive a new commitment on Longhorn at a rate and on terms that we found constructive, resulting in 80% of Longhorn's capacity being committed beginning next year with an average remaining life of six years. In addition, the customer who has exclusive use of our Corpus Christi condensate splitter recently extended its take-or-pay agreement for the facility until the end of 2024, providing additional length to that contract. We think both of these developments underscore the quality of our assets and the value that our customers see in working with us. Operator, we are now ready to open the call for questions. Thank you. If you would like to register for a question, please press the one followed by the four on your telephone. You will hear a three-tone prompt to acknowledge your request. If your question has been answered and would like to withdraw your registration, please press the one followed by the three. If you're using a speakerphone, please lift your handset before entering your request. Once again, if you would like to register a question, please press the one followed by the four. One moment, please, for the first question. Our first question is from the line of Jeremy Tonet with J.P. Morgan. Please go ahead. Hi. Good afternoon. Good afternoon, Jeremy. Thanks. Just wanted to kind of pick up a little bit more on capital allocation, and all of your comments there were very helpful. Just wondering, within the context of rates moving kind of as quickly and sharply as they have recently, does this impact your calculus, you know, going forward? Or if you could just talk a bit more, I guess, on rates and if that changes anything you're thinking. Well, just to clarify your question, Jeremy, are you talking about the rates we charge for pipeline movements or, you know, the general interest rate environment and its impact on how we may see our valuation? Apologies. I meant interest rates specifically. I'll save other rates for later. Yeah. As we look at it, you know, we keep an eye on what we think fair value of the company is. You know, an increasing rate environment does impact that evaluation. I'm not gonna go into all the details of that evaluation, but we certainly consider it. That will continue to weigh into our decision about the value we see in buying units back, but we certainly consider it. Got it. Implicitly, you're happy with your leverage ratio. You don't need to kind of adjust any of that at this point. You're at a good point. Well, I'm not sure it's related to the leverage ratio. I think it's important, you know, interest rates in the general environment. Recall, we've been a long-term issuer of 30-year paper. In terms of, you know, rising rates and an immediate impact on our interest expense and cash flows, you know, we've essentially paid for that insurance over the last several years. We just don't see that same headwind given the fixed nature of our debt and the duration of that debt. You know, rising interest rates aren't going to impact sort of our interest expense or cash flows here over the short term with the debt that we have. That makes perfect sense. Not everyone takes the same conservative approach to stacking out debt. Thank you for that. Then maybe just for tariffs, real quick, turning that direction. You know, it seems like you're going to have a lot of headroom for rate increases going into next year here. Not finalized just yet, but just how do you think about, I guess, pacing in the increases, whether it's on a multi-year timeframe or just any other thoughts on the strategy and tariff rate increases under what's allowed under the indexation methodology? You know, I think we spent a little time on this last quarter, and I don't think our perspective is changing. You know, we wanna be thoughtful about how we move our rates, and we're taking the time to really dig into our markets and understand the competitive dynamics of where we are. I mean, I always like to remind folks, even our indexed rates, we have competition. There are other service providers in that market, so we have to be cognizant of that. We haven't made any decisions about, you know, how we wanna pace into it or not pace into it. I don't have any specifics to add to that, Jeremy, other than to say we're gonna be thoughtful. In any event, as we sit here today, you know, the rate increases that we're expecting, we still think are gonna be quite healthy. The question is going to be around the margin, how healthy they're going to be. That's right. That makes sense. I'll leave it there. Thank you very much. Our next question is from the line of Theresa Chen with Barclays. Please go ahead. Hello. Thank you for taking my questions. Aaron, I'd like to go back to your comment about the annual guidance first, just related to the annual bump not reflecting the full, outperformance of third quarter and the conservatism baked into it. Can you elaborate on, you know, what exactly do you mean by conservatism? Which areas of your business, whether it be refined product volumes or costs that you could see, you know, underperforming a bit in the fourth quarter? Well, I think the one item I would point you to specifically is just the volatility in the commodity markets, in particular, basis differential. That's one. We have, as I mentioned in my comments, most of our margin for the fourth quarter already locked in. But as we've also talked about in the past, we can't really hedge the majority of our basis risk, and it's been very volatile. As Jeff mentioned in his comments, you know, there was a point in time earlier in October where the typical differential would be, you know, New York Harbor - $0.10. This year it's been, you know, New York Harbor - $0.30 and sometimes even wider. We had the complete opposite thing happen, where that went from a minus, call it $0.20 To a +$0. 30 or +$0.40, and in some cases higher at moments. We've got a lot of. It's not just that it's wider, but it's a lot more volatile. To give you some sense, you know, a nickel move in that basis is worth about $10 million on an annual basis to us. When you're talking about swings of -30 or -20 to +60, it causes us to be a little cautious about how is that market really gonna move in the fourth quarter. That's one specific thing that I would point to. The other thing I would point to is just a recognition on our part that general economic conditions are important. You know, our business has proven through the years to be really resilient, even through, you know, recessionary times. We expect that resilience to continue. As you get into shorter durations of time where you're trying to provide guidance and what to expect, we don't wanna ignore that, you know, there's still some economic uncertainty out there. If or when that uncertainty actually starts to manifest itself, when's that going to occur? We're trying to be, at least recognize that potential as well. It's not anything specific to volumes we expect to be higher. It's not really that. It's really more of the commodity-related volatility around basis and just the general recognition that the overall macroeconomy has some uncertainties in it at the moment. Got it. Speaking of macro uncertainty, as it relates to your refined products business, what are you seeing in terms of demand? Just taking into account the quarter-over-quarter slight decrease in total volume shipped, and it seems to be tracking, you know, below the previous annual guide of being 4% above 2021. Curious what you're seeing there. Yeah. Well, what's interesting in the schedules we I think attached to our earnings report, if you do the math on total refined products for year-over-year, year-to-date, we're up about 4% versus the 2021 period. In terms of volume, it was down slightly, almost, you know, 0%, I think, if you did the straight math, quarter-over-quarter. For the year so far, we are up around 4%. As we look at the whole year, you know, I think we're going to be in that, around that 4%, maybe a little below, maybe a little above. I think we're gonna be sort of in that range. From a volume perspective, things are tracking and it's holding in there. One piece of color I would add to the volume, you know, we've in the past been talking about coming out of 2020 and post-COVID and the growth. As we sit here today, and as we look forward, I think we've seen probably most of the rebound or quick rebound that we're going to see. Our rural markets, of course, rebounded quite quickly and quite significantly. The markets we've been waiting to see are our more metropolitan markets. Think of Minneapolis, St. Paul, think of Kansas City, think of some of those more metropolitan areas, and they still seem to be a little behind the pre-COVID era volumes. That just may be with us for a little bit, Theresa. We're not necessarily giving up hope that it won't get back there, but it just may be over a longer period of time as many of those cities still sort of get back to normal as defined in 2019. We could debate whether we're in a new normal or not, but I think that's the reality of where we're at. I think we've seen most of the recovery we're gonna see from pre-COVID period of time, with our metropolitan areas still lagging a little bit, but many of our rural markets are above where they were in 2019. Boil it all together. Sorry for the long answer. Volumes we expect to still grow year-over-year. Got it. That's very helpful. Thank you. For the rate, what you saw in the third quarter related to longer haul movements from the Gulf Coast to the Mid-Con due to refinery supply disruptions, would you expect that to continue given the ongoing downtime at BP Whiting, Toledo? I think so. I mean, as long as the refineries, you know, in Toledo and Whiting are down, I think there's the potential for us to have to supplant with longer haul supply into those markets. As we've shown, you know, demand is pretty resilient. It's seasonal, but it's pretty resilient, so that bodes well for us for however long that condition exists. In terms of, you know, how long or to what extent that continues to exist, that's yet to be seen. Markets are fluid, and they move around, and the longer a condition exists, they adapt in different ways. Generally, we think that's a positive tailwind for us for as long as it exists. You know, with refiners running at, you know, high 94%, 95%, with inventory low, being fairly low across the country and in our system in many ways, you know, the market has lost the ability to just, you know, respond to short-term disruptions, and it has to find barrels to match those disruptions from other places, so to speak. We think that bodes well. It's unpredictable. It's hard to predict if or when further disruptions may occur. That lack of sort of built-in resiliency that has existed in the past in the market, we think is also a contributor to, through time, seeing longer hauls when we see disruptions. It wasn't just the Mid-Con. We've got longer hauls out to West Texas, the Gulf, the group movement. Obviously, we had longer hauls, but we also have longer hauls within sort of the footprint of our system as our shippers and customers adjust to this new market. It's really long-haul shipments generally in almost all areas of our pipeline system. Thank you. Our next question is from the line of Keith Stanley with Wolfe Research. Please go ahead. Hi. Hi. Thank you. First, just the crude product margin for the quarter. I think it was $27 million, and there's probably some mark-to-market type stuff in there, but it's a pretty big number versus history for the company. Can you talk a little about what the opportunity was in Q3? Was it just the marketing arm moving volumes where you had space, or was it other types of activities? Well, it was really spread among many different activities. I think how I would talk about and really encourage you to think about our crude marketing activities is it's very much an optimization game for us. It's one that, you know, relatively speaking, we're still fairly new to the crude space. I mean, yeah, we've been doing it for 10 years, but in the grand scheme of everyone we're competing against and how that market has evolved over centuries, we're still new in many ways. We're continuing to learn, and we're continuing to get better, frankly, at taking advantage of opportunities that present themselves to us than we have in the past. I think that's going to continue, our ability to, you know, maximize the value of our assets based on opportunities that present themselves. Will it always be, you know, an outperformance by, you know, $27 million or whatever? I don't know. The point is, we're working to make sure we're maximizing that value as much as we can. What's driving that value is, you know, things like quality differentials. It's things like location differentials. It's things like the combination of quality differentials and location differentials. It's a lot of different sort of opportunities that present themselves that frankly we're just better today than we were even a year ago being able to capture. They're gonna be unpredictable, in terms of exactly how they present themselves. We also, as we're learning and executing on these opportunities, remaining mindful of the quality expectations and quality service that our customers expect. We're balancing our ability to maximize the opportunities we see with the expectations of our customers and what they wanna see. As we see opportunities, we're gonna try and grab them, and we're just getting better at it. Interesting. Thanks. Second question is a big picture one, just, with the IRA passing. Aaron, you spent a lot of time at the Analyst Day kinda going through the data and the details on EV adoption and long-term views on impact to the company. Any updated thoughts you'd share on how you look at the IRA and some of the benefits for EVs and just updated views on the topic since you've kind of dove into this in detail before? I'm happy to talk a little bit about it. I think at a summary level, the IRA doesn't change really the views that we expressed back in April of this year. The reason it doesn't change it much is implicit in a lot of our conversations assumed that we would have significant EV subsidies. That was sort of implicit. The fact that they're there is not really new information to us. One thing I will say about the EVs is, you know, the manufacturing requirement and the input requirements in terms of being domestic or not coming from foreign sources is one that, you know, makes getting the full benefit of that incentive more difficult. There's no way I think around that. It's gonna be more difficult for consumers to achieve because the product is gonna be really hard to meet the thresholds to get it. I could make an argument that the incentives in place are probably more restrictive than the incentives we thought would be in place when we were talking about this in April. That's sort of getting into the minutia of it. I think the other area about IRA that I would focus on are the incentives for, you know, CO2 sequestration. You know, those, they've increased the benefit there under the 45Q credits, from where they were before. That's, you know, incrementally making CO2 projects and things like that more competitive or more economic. I'm not sure that it's a game changer in terms of the opportunity set overall. Much of the cost to capture CO2, if you're really trying to get at the heart of where the emissions are, you know, $85 with the incentives still really don't clear that bar in most cases. I'm not sure that changes our view from April, again, on what that opportunity set may look like. It could in the margin on very specific projects down the road. As a general rule, probably doesn't move the needle. You know, the additional incentives for things like Sustainable Aviation Fuel, I think those could be interesting. It's certainly making it more economic for the producers of renewable diesel to consider taking some of that capacity or adding capacity to produce more Sustainable Aviation Fuels. That's net positive. If I were to put all that together, I would just say that it's not materially changing the views that we had in April. Thank you. It's probably more than you wanted, but you. Our next question is from the line of Praneeth Satish with Wells Fargo. Please go ahead. Thanks. I think if I heard correctly at the end of your prepared remarks, you mentioned signing up a new contract on Longhorn. I was wondering if you'd provide any more details on that, how large of a contract, and the duration. I guess, how do you balance contracting more capacity on Longhorn versus waiting for takeaway to tighten in the Permian and maybe contract at a better rate in the 2025 timeframe? I mean, do you have a view that takeaway may not tighten that quickly and that's why you're kind of contracting now? Well, I'm gonna start with your multipronged question with the last part, which is, you know, the general thesis of, you know, differentials are low right now. Why wouldn't you just wait till they're better before you contract it? What I would say is we certainly think about that and how do we balance that with, you know, being able to get committed barrels and reduce cash flow risk over the long term. That's the balance. In this particular case, we had a customer where, you know, our views of the world overlapped in such a way that we thought it was a constructive rate, even if you look longer term at the forward curve on the differential, which we can all debate whether that forward curve on the differential is accurate or not. If you look at it, which we do, and you look at what the customer was wanting to accomplish, we overlapped in a way that we think it made sense to do. It's a case by case. I'm not sure it's a general philosophy on our part, we're gonna go lock everything up or we're not gonna lock it up. It's very much a case by case, deal by deal evaluation on our part. In this case, we thought it made a lot of sense to do. Going to the first part of your question, you know, in my notes or my comments, I mentioned that the average utilization committed on Longhorn beginning in January 2023 will be around 80%. Before the contract, if we sit here today, we would have told you it was 75%. It's about a 5% increase on the average overall. Of course, you also have to think about is where that utilization would be, you know, next year and the years after that. At the end of the day, from where we sit right now, we're going from roughly 75% utilized to 80%. If you were to think about the duration of it, essentially what's happening is, you know, we were at a five-year duration, six-year duration, and we're keeping that same duration essentially going forward. We're gonna get the higher utilization essentially committed over roughly a six-year period, versus if you hadn't gotten it, that weighted average term would have gone down probably by about a year just because of the years passed since we last talked about it. Hopefully that gives you enough detail. I just don't want to get in all the detail in specific contract. Just suffice to say, higher utilization for a longer period of time. I think it's really, really interesting that, you know, we've got our crude contracts generally, if you overlay it with the period of time between 2024 and 2026, when I think most estimates would show capacity tightening. I like where our contract terminations sort of sit in relation to that tightening. That's very helpful. I guess I wanted to go back to Jeremy's question on rates and the impact on capital return, but I guess I just ask it a different way. Specifically, has there been a thought to potentially shift more of the capital return to distribution growth? Interest rates are moving higher and now you can get a high single-digit yield from a lot of places. Do you feel like your yield is competitive enough in the current environment to attract capital? I would hope so. I know yields have gone up, but when I look at the absolute yield on our units and compare that and risk adjust it versus some of the other higher-yielding things that are out there, and you truly risk adjust it, I think we have a really strong value proposition, frankly. As an MLP, depending on, you know, where you're at in your own individual, you know, tax status, you start taxing some of those yields. I think that's an additional benefit to investors in our units, their ability to defer a lot of that yield for some period of time, again, depending on when they've come in and where they're at. I think it's extremely attractive, frankly. It's probably also worth keeping in mind that the historical spread between Treasuries and our yield and corporate, borrowing rates and our yield has been at all-time highs recently. Those aren't normal. I mean, that's not the norm for the last 20 years. Those spreads have been a lot narrower than they were a couple of years ago before this recent run-up in rates. There's no reason to think that what they were before this run-up in rates was the proper rate that should hold going forward. It's probably the opposite is more true. This would represent more of a normalization. As we think about it in totality, the distribution we think is attractive. You know, we're gonna continue to, we understand that's an important part of our value proposition. At the same time on unit buybacks, it's gonna remain subject to our views of value and timing and, you know. I don't think it changes that a great deal for us. Got it. Thank you. Our next question is from the line of Neel Mitra with Bank of America. Please go ahead. Hi, good afternoon. I wanted to touch on the crude segment. This is the second quarter in a row that Longhorn and BridgeTex have had lower volumes, and you've collected deficiency revenues. It seems like the language around it has changed. It seems like this time you said timing versus second quarter, it seemed like more volumes were flowing to Corpus Christi to generate a higher netback from the export market. Could you comment on the timing of volumes there and what you mean by that? Well, I think the timing comment really is meant to encompass the fact that our shippers are making different decisions with what they're going to do with the barrels coming out of the basin. They still have a commitment to us from a revenue perspective. They're either gonna pay us deficiency or they're gonna move the barrels later. The idea is that we expect them to move the barrels. They're just doing something different with them right now than what we would otherwise expect. That's what drives the timing comment, is it's really we expect the barrels to flow. They just may flow at a different time or at a later time in their commitment than if you were just ratably sort of charting it out. The reason behind why they may be shifting that timing is the desire to go to a Corpus or take advantage of some other differential that they wanna see. As we look long term, we think Houston's well-positioned, and those barrels will wanna come back and go to Houston for one reason or another. It's really those, both of those items. The timing comment is meant to be, I think, more general in terms of we expect the barrels to flow just at a different point in time than you would have if you put them on ratably. The reason why it's maybe less ratable is because shippers are making different decisions of what they're doing with the barrel right now. Does that clarify it for you? It does. Maybe I can ask a more specific question with their new customer on Longhorn going from 75%-80%. You said you had a shared philosophy on rates in the Houston market. You know, can you share what that philosophy is and why you think the volumes will eventually return back to Houston as kind of the market that we should look to? Well, I think there's a couple of things happening. One, I think some of it's gonna depend on what do you view about exports. If you just look at the state of play today, I don't think there's any question that if I'm a producer and all I want to do is export it, that's it. That's all I'm interested in doing. Corpus has some advantages over Houston. It's a little cheaper to get there via pipeline. Some of the terminal capacity is a little more efficient for large scale export. So it's more cost efficient today to get down to Corpus if all you wanna do is export. Question is how long is that going to occur, and is that really a permanent solution? How will Houston evolve through time, given that? Our expectation is that Houston provides you a lot more optionality as a producer into a large refining complex, which Corpus has some refining complex there, but not as much as Houston. If you move it to Houston, you can also get it over to Louisiana. Through time, we think exports in Houston are going to continue to become more competitive with Corpus for exports. As we look at Houston and we think about it, as that market evolves, it should again, through time, pull more barrels to Houston. Secondly, we're dealing with a pretty exacerbated condition right now in terms of crude oil market leaving the world market and meeting those exports. Now, you can come up with a bunch of different sort of assumptions or beliefs around how long it's gonna continue to the extent that it's going to continue. If some of the pressure on exports abates, again, we think Houston, for the reasons I just mentioned, is the more attractive market over the long run. That's really helpful. If I could ask one last question. You mentioned the gas liquids blending margin was $0.75 during the third quarter, and the basis really worked in your favor kind of in September. Is it fair to say that $0.75 is either, you know, kind of flat or moving up in Q4 just right now because you're getting the full advantage of the better basis versus Q3, where you only saw it towards the end of the quarter? I would love to tell you that the basis has not, as we speak, already flipped back to the other sort of condition. It was a short-lived benefit that really impacted, you know, a portion of the third quarter that has abated since we've entered the fourth quarter. Unfortunately, no, I can't say that benefit is going to flow through to the entire fourth quarter. That's just the reality of it. Is there anything to be able to track that basis? It seemed like, you know, the Mid-Con was short, you know, product, so it was able to attract some product back. Is there anything we can look at to maybe try to predict that? Well, you may not be able to predict it perfectly because the markets I'm about to reference will, I think, give you an indication or a view of things. The market being volatile, it's day to day, hour to hour in some cases, in terms of what the basis will be. If you're trying to get a sense for where that basis is, look at the NYMEX New York Harbor price and look at a Platts Group 3 price, and the difference between those two will be indicative of the basis that we're talking about. Again, it won't be perfect, but it is something that you can look at to get a sense for it. Right. Okay. Thank you very much. If you're trying to do it on a futures basis. Yeah. Just to round out, if you're trying to do that on a futures basis, you have to be a little careful 'cause the Mid-Continent market is much more of a physical market than it is a futures market. Hence why it's difficult to hedge this basis. If they were both futures markets, you would have a more efficient instrument to sort of deal with it. But the fact that the Mid-Con is much more of a physical, I don't wanna call it spot, but sort of right now business compared to NYMEX being more of a futures market in most cases, at least as we're referring to it, that creates some noise in being able to compare those. You just have to make sure you're taking into account time and a futures market dynamic compared to a more physical market dynamic in the Mid-Con. Got it. Appreciate all the color. Our next question is from the line of Gabe Moreen with Mizuho Securities. Please go ahead. Hey, good afternoon, everyone. Can I ask about the splitter contract and maybe relative or the re-up there, the extension through 2024 at a time, I guess, when the economics for that asset are pretty healthy, to put it mildly. To what extent that may have been paired with the Longhorn contract as well. Then also, you know, as you look through alternatives, did you, I guess, consider a lot of other things for that asset which is pretty well positioned at the moment? Yeah. The Longhorn contract and the splitter renewal are unrelated, so that there isn't any interplay there. In terms of the term to 2024, it was a term that we were happy with, frankly, going out to 2024, and our customer was happy going to 2024. I think both of us realized the economics are pretty favorable for the splitter right now. Getting a little more term on that was, we thought, beneficial to us. I also have to highlight that, you know, as we talked about the splitter in the past, that our exclusive customer had, you know, renewal options on the splitter, and the sort of economic terms of those options were pretty much set. What we've ended up doing is getting what we expected to get. We're getting the economic trade that we got, and we're getting the term out to 2024, which we found attractive. In terms of, you know, how we think about the splitter long term, you know, it's. We do look at other alternatives. Is it something that we would be comfortable operating ourselves? For now, we've decided that we're very happy that our customer is staying in it long term. Is that going to be the case? I don't know. We'll get down to 2024 and we'll have those discussions at that point in time and figure out where we're at. We were happy to get the additional term as we sit here today. We're happy with our customer, but we're also not ignoring the long-term economics of the splitter either in terms of what it might be able to do for us. Maybe we don't wanna lock it up for, you know, ever, so to speak. Maybe something changes. For now, we're pretty happy. Thanks, Aaron. Maybe if I could just ask a quick one on the El Paso contract, where that expansion stands on the usual 6x-8x multiple that you're referencing with expansion projects. Yeah, it's gonna be in that range, probably the lower end of that range if things work out. If things work out the way we expect them to work out, it could even be better. Great. Thanks very much. Our next question is from the line of Michael Cusimano from Pickering Energy Partners. Please go ahead. Hi. Good afternoon, everyone. Coming into the year, I believe you guided refined products transport rates to flat year-over-year despite the higher uplift, and it looks like the average tariff is trending higher than that. Can you kind of update us on how you see that going forward, and if there was conservatism coming in, or if it's just trending higher with some of the dislocations you're seeing in the markets? Well, as we think about and we provide guidance on tariff rates, there's really a couple of assumptions that we make. One is, what is going to be our mid-year tariff adjustment? You know, it's beginning of the year, we haven't made that adjustment yet, but we have some ideas about where we think that's going to come in. The second assumption that we make in there is what happens to the supply patterns on our pipeline. In other words, put it in specific terms, what's the average haul per barrel, so to speak, on our pipeline system? Our approach has often been is we've got a long history of knowing sort of how long those pipeline movements are, and it's that, you know, it's that average haul times a tariff is what gives us the actual tariff we realize. As we came into the year, you know, even with the expected increase mid-year on the rate itself, you know, the average haul wasn't necessarily increasing or changing from our historical patterns. That led to, if you put that in the machine and put those two things together, it led to generally a fairly flattish overall expected rate that we would realize, hence the guidance we gave. We sit here today, what we've experienced so far this year, some of it due to market disruptions, is the length of our haul is getting longer than what we thought it would be. Now we're getting longer hauls at the higher tariff given the mid-year tariff increase, and that's resulting in essentially a higher realized rate. That's the sort of detail of, you know, guidance. We were not assuming the haul in our system to necessarily get longer. In many cases stay the same or in some cases get a little shorter. What's happened is the opposite. It's actually getting longer and some of that driven by unforeseen disruptions in the markets that we serve with the refineries being down. I'll stop there and see if you have any additional comment or question around that. Yeah, no. That's very helpful, Aaron. Yeah, one follow-up on that. Do you think that there's been a structural shift to where that, you know, longer, call it like, you know, more barrel miles in your system continues, or is it hard to quantify or forecast because, you know, it's just short-term dislocations that we've seen in the market so far? You know, as we bring on, you know, our expansion, for instance, to El Paso and you compare that haul to, you know, our average haul, that's a longer haul, so that would lead to net net, potentially a longer haul in the system as a whole, especially as we're going all the way out to El Paso. I think there may be, in some areas, some structural shifts that could benefit us. In terms of the disruptions, it's hard to predict where disruptions are going to occur, what's the nature of the disruption, the duration of the disruption. I think something that we need to keep in mind is that whatever resiliency was built into the system before in terms of inventory levels and then refineries, there's less resiliency in the system today. You've had things like refineries just shut down. Refinery in Cheyenne, refinery in New Mexico. As those shut down and we backfill those, it leads to a longer haul. I know this is a long-winded answer to say there could be some structural shifts that repeat themselves that end up to a longer haul. We haven't done all of our work to see how we think that's gonna shake out for 2023, but it's possible that we do start experiencing some longer hauls than what we had experienced, you know, three or four years ago. Longer haul than what we're experiencing this year, I don't know. Certainly over three or four years ago, it's a longer haul. As refinery rationalization and disruptions happen, I think we're well positioned to benefit as that occurs. It's less predictable. Okay. Yeah, that makes a lot of sense. Then one more, if I can. Aaron, your comment on the metro areas that are somewhat lagging the recovery, I just wanted to make sure that's the metro area as a whole, their consumption, not specific to your system. Is that right? Well, in some of these metro systems, we're a significant part of the supply into those, so it may not be on the whole, but what we're seeing, at least for the share that we supply, may be down a little bit. My comments are reflective more of what we're experiencing in the metro areas. Okay. Great. That's all for me. I appreciate the help. There are no further questions on the line. I'll turn the call back to Aaron for any closing remarks. Well, thank you all for your time today. Just to reiterate, we're pleased with the third quarter financial results, as well as the new project to expand our refined products pipeline capabilities to El Paso. We remain focused on finishing the year strong, managing our business in a responsible manner, and focusing on maximizing the value for our investors over the long term. On behalf of Magellan, we appreciate your continued support. Thank you, and have a nice day. That does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.