I'm responsible for investor relations with Magellan. Sorry about that. For those of you who know us well, you know that we have an Analyst Day every other year. Because of the craziness of 2020, we've not hosted this event for four years, and so we're really glad that you could join us today. Today, I'll go ahead and kick us off real quick by going through the agenda and then talking about a few housekeeping items. As you well know, our CEO, Mike Mears, has indicated he plans to retire at the end of April. He is here with us today, and will talk through Magellan's, really the keys of Magellan's success, quite frankly. From there, he'll hand the baton to Aaron Milford, who's our Chief Operating Officer. Aaron will be moving into the CEO role in May of 2022 once Mike departs. Aaron today will talk about, I think, some areas of interest to you today, some very important topics, including energy transition, as well as the long-term outlook for our company. We'll take a short break, and then we'll dig into the business units. Our Commercial Senior Vice Presidents, Mark Roles, will cover Refined Products, which is about 70% of our operating margin. Robb Barnes will cover our Crude Oil segment, which is the remaining 30% of our operating margin. At that point, Jeff Holman, our CFO, will kinda wrap it up, if you will, talking through capital allocation and other financial issues of interest. Then Mike will close us out at the end. Following the presentation itself, which we think will last just the next few hours, we will host a lunch for those who would like to stay with us and mingle a bit more with Magellan's management team. In addition to the presenters that I just mentioned, we have a few other representatives here who will be helpful for any questions you might have. Michael Aaronson, if you'd like to raise your hand real quick, is our Senior Vice President of Business Development. Melanie Little is our Senior Vice President of Operations. She also has environmental health and safety also. Bruce Heine, off to the right here, is our Vice President of Government Affairs. And then we have Barry Pearl here as well, sitting in the middle, who is currently our Lead Director and will become our chairman once Mike departs. A few other housekeeping items. Q&A. Each of the sections will have their own question and answer session. Heather and Carrie, who you met when you were walking in, and I will have microphones that we'll just be going throughout the group for anyone who would like to ask the question so that, one, the folks in the room can obviously understand what the question is, but also those on the webcast as well. There are cards on the tables that talk about the Wi-Fi code for those who may be interested. We also have tables in the back for the tall tables, quite frankly. If you wanted to stretch your legs, you can go back there to stand if you'd like to. Then we also have some charging tables just in case you run out of juice on your phone or your computer. Restrooms, in case you're interested, are just right out these doors off to the left. Before we get started, I will need to 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. With that, I'll hand it off to Mike Mears, our Chief Executive Officer, to talk about Magellan's track record. Thank you, Paula. Is this working? You guys hear me? I think we need to back up a slide. All right, there it is. Well, first of all, welcome to all of you. Thanks for coming today. I think, you know, Paula mentioned that we have not hosted this for four years because of what happened in 2020. But the reality is we did have a webcast analyst meeting. It was on March 23th, 2020. I won't forget that day. A lot of things happened on that day, and it was kind of a rushed together. We had an analyst presentation ready to go, and it was completely thrown out the door. I think we spent that whole time period just talking about refined product demand and what was gonna happen. Really, it was just kind of more of a damage control analyst day. It's nice to be back in person and to be a little more calm and relaxed and talk about, you know, the prospects of the company over the next 10 to 20 years and not just the next six months. We're glad we're past that. One of the advantages of being headed towards retirement on my way out is I have a very small speaking part today. What I'm gonna talk about, really just to kinda level set, before we get into forward-looking topics. It's just kinda the history of what's made Magellan such a strong company, and just to reset everyone, with regards to where we've been over the last 20 years. You know, first of all, we've got a great set of assets. We have assets that are critical to the functioning of our economy. In the Mid-Continent, the middle third of the country, we transport between 40%-50% of all the refined product to the market. If you get into the upper Midwest, the upper third of that, it's closer to 50% or above. It's critical infrastructure, and its resiliency is pretty impressive. Mark Roles is gonna have some slides showing refined product demand over our 20-year history, including through the pandemic, and it's pretty impressive how resilient the business is. That's not gonna change. Aaron's gonna speak to that quite a bit today about our expectations for what the future looks like. We expect those assets to continue to be a critical part of energy delivery to the United States going forward. We also have had a consistent commitment to our balance sheet. You know, when we split from Williams 20+ years ago, you know, one of the things we kind of set as a fundamental principle is we were gonna keep our leverage at 4x or below, and we've done that. Early on in our history, we were kinda low organic growth. It was mostly growth through acquisitions. The middle part of our history up till now was high organic growth, expansion capital, and now we're in an environment of low growth and a capital return to unitholders. Through that entire period, we've kept our balance sheet or leverage at 4x or below. We've held firm to that, and we've performed over that entire 20+ year period. We've done that with issuing very little equity. Over that time period, we had one equity offering that was relatively small, and we've raised our distribution consistently every year since over the last 20 years. We're pretty proud of the commitment we've made to our financial discipline and the way we've performed over the years. Responsible governance and operations. We were one of the first to eliminate the GP and the incentive distribution rights. We were one of the first to have independent board members elected by unitholders, and we're proud of our record really with regards to governance that's responsible to our unitholders. Our operations. We don't talk much about our operations in investor meetings. We usually talk about balance sheet. We talk about commercial projects. We don't talk about our operations that much. We've got a great operations team, and we've got a tremendous record of improvement from efficiency, safety. It's something we should talk about more. Just to give you an example, I'll give you one highlight from last year that we're very proud of. You know, we've got 13,000 miles of pipeline. Last year, we moved over 1.2 billion barrels of fuel. From our pipeline's releases, we had three barrels. We had three barrels of releases for the entire year of moving 1.2 billion barrels of fuel. We should talk about that more 'cause we're proud of it, and we've got a culture of continuous improvement, and our operations is something that I think a lot of the industry looks to to try to emulate what we do. Lastly, we have a disciplined management team. We're in a period of transition, but one of the messages I wanna leave with you is just that none of these things are gonna change with the transition that's taking place. Aaron Milford, who's gonna come up here and speak in just a second, he's been with the company his entire career. He was CFO for a period of time. He was Chief Operating Officer, you know, up until this transition. He's been with the company through this entire process. Many of these things, you know, were a product of his work through that entire time. That's not gonna change with this transition. Jeff Holman, our CFO, has been with the company his entire career, and is responsible for, you know, the strong financial discipline that we have. Mark Roles and Robb Barnes have been with the company their entire career. This entire management team is ingrained in the culture that we've had over our entire history, so you can expect the same kind of performance going forward. With that, I'm gonna turn it over to Aaron, and we'll get into the meat of the presentation. Thank you. Well, good morning. We're doing some technical things back here, so I already have to do the stall. It's good to be with you this morning. I don't know about you all, but it feels really good to be back in person. We've been on Zoom calls and really looking forward to talking with you today. I'm obviously very excited about the transition. I've got some big shoes to fill. Mike has had a really long and successful career. I certainly hope to continue that. You know, one of the first things that I'm trying to do in this transition is get off on the right foot. I thought, well, at the Analyst Day, if I'm trying to get off on the right foot, why don't I pick, like, the most controversial, difficult subject for us to talk about, which is energy transition and EVs? That's what we're gonna do because we think we have, actually, a really good story to tell. For the next hour or so, we're gonna talk about energy transition, how we think about it, what we think is going to play out, at least our opinion, and then we're gonna transition, and we're gonna talk about electric vehicles more specifically. How do we see those being adopted? That's a specific portion of energy transition, but one that is obviously very important to our business. Then we're gonna put a bow around that, and we're gonna talk about what we think energy transition, EV adoption, and how we're gonna run our business, what do we think it means for valuation. We're gonna think about a lot of long-term trends here. I hope that at the end of the day, what you find is a lot of confidence in how we're moving forward and how we think we're gonna have a very strong company for a very, very long time, but most importantly, understand how we think about it and why we think about it the way we do. A couple of notes, some things to keep in mind. I don't think you're gonna find me standing up here claiming that I have all the answers to energy transition. Frankly, I don't think anyone has all the answers to energy transition. What I do hope comes across is that we don't have to have all the answers. We need to have some answers or some ideas, some ways to think about energy transition so that we're running the company properly, but we don't have to have all the answers, and we clearly don't. Again, we don't think anyone does. With that intro, let's dive right in. The slide that is up is a framework. When we think about energy transition, we're talking to Barry and our board, and we're trying to frame up, well, what does energy transition mean? Where is it going? Where's the momentum? What things need to exist for energy transition to continue? What things need to exist for it to determine the pace of that energy transition? What's interesting is, in the United States at least, the concept of energy transition, while we're talking a lot about it today, currently, it's not a new concept. The idea of energy conservation, being smart with how we use our resources is not new. One of the first things that came into play was in 1975. Anybody guess what that was? The CAFE standards, the Corporate Average Fuel Economy, were established in 1975. Obviously, those have changed a great deal throughout time. Sometimes they get more aggressive, sometimes they become less aggressive. Since 1975, we've been dealing with a desire by many to reduce, for whatever reason, reduce the amount of petroleum that we use. That's 1975. We have the next portion, I think, of an energy transition, and that was the monumental shift from coal to natural gas, for the generation of electricity. The year that natural gas overtook coal in terms of U.S. for energy production was 2016. That took about two decades to occur. Just so happens, well, that happened in 2016. I think worldwide demand for coal today in 2021 was actually the highest it's ever been, which is an interesting fact, in and of itself. But the main point I'm trying to make here is that the idea of a transition, the idea of conservation, using resources is not new. This industry has been going through it, in different phases for a very, very long time. The framework that we're trying to use here is one where we're trying to look at what we think are three key forces to energy in transition. At the top of the triangle is policy. What are the government regulations? What are the political desires? What things are driving policy, and how are those policies encouraging behavior? On the bottom left of the chart, you see capability. This is where we may want to do all these things, whatever those things are, but there has to be an actual capability. We have to be able to do them, and we have to be able to do them reliably because the consequences of not being able to sort of effect what we want to effect are very significant. Then on the bottom right is the consumer. Also, you could just It's consumer slash market. It's what do consumers need, want, value? What will markets accept? What will markets not accept? These three forces, policy, capability, consumer or markets, there has to be a balance between those three in order for the transition to move. If any one piece of this gets out of balance, you may make some progress, but you'll usually stall. Then you have a feedback loop among all three of them. What consumers want informs policy informs capability informs both consumers and policy, and you get into this big feedback loop that's trying to force all three of these forces to balance. In the middle of all that, you've got external shocks. We don't have to look very far to see a couple of them. Tragedy in Ukraine, COVID before that, high inflation even before the tragedy in Ukraine. Those are all external shocks that cause this feedback loop to increase or decrease or emphasize one part of these one force over another, but the key is they need to balance. When we think about energy transition, and you're wondering, "Well, how does Magellan think about energy transition?" This is the lens that we're using to look at energy transition. Let's take the first force, which is policy. It's clear that a lot of policymakers want to drive energy transition faster. There's really no question that there is a desire to drive energy transition faster. You see it in subsidies for electric vehicles. You see it in really quasi mandates for electric vehicles. You know, the new CAFE standards proposed, I think it's 55 miles per gallon for a 2026 model year combined light-duty car and 40 miles per gallon for a light-duty truck in 2026 model year. If you do the math on that, it sort of back solves into a mandate for about 17% electric vehicles have to be in the fleet. In other words, if you're gonna meet those objectives, you have to have 17% of the sales of that model year be electric vehicles. We're seeing that sort of momentum. The automakers are following suit. They've got the message. They're coming out with their own commitments. Now, they're non-binding in a sense, but they do have commitments. They're making investments to try and produce more electric vehicles. You also don't have to look far to see examples of attempts to limit fossil fuels, whether it's the approval of pipelines to move the fuels to market, whether it's making it more difficult to get permits. You know, pick whatever tool you wanna use. You're seeing tools used to try and limit the production of fossil fuels. Then last but not least, you have just general low carbon efforts. Europe's way ahead of the United States in terms of, you know, sort of an EU or a continent-wide carbon market. We don't have that here in the United States. You have states like California, Washington, Oregon, which you guys are all familiar with, I'm sure, driving low carbon fuel standards. You see all this momentum about that. There's also another side to this, and that other side, and the main point of this slide is there's not a consensus around that, really. We don't have a clear political drive and just a clear majority that want to do all the things on the left side of the page. You see that through some evidence. Build Back Better, we put stalled, failed to pass. You guys have no idea how much time we spent talking about how do we wanna describe what happened to Build Back Better. It didn't make it the first time around. There weren't enough votes. Yeah, it came down to maybe one or two votes, but in the grand scheme of things, there weren't enough votes to get that through. Now, it may come back in some form or a scaled-down form, so it can come back, but it didn't make it. You have another example of that, which I'll talk about in a moment, but just to bring it in here, that is in the state of New Mexico. New Mexico was considering a low carbon fuel standard. It didn't pass, and one of the primary reasons it didn't pass was because of the political concern about the economic costs and the consumers if they passed it. It was gonna cause fuel to be more expensive. The politicians decided they did not want to do that at this time, so it failed. Again, it could come back, but it hasn't passed yet. In the United States, the lack, frankly, of a federal carbon tax, we think, is some evidence that there's not a clear consensus. First of all, United States citizens aren't real fond of taxes generally, and the idea of attaching a carbon tax is politically very, very difficult. No one wants to do that. What has that led to? Well, what it's leading to is a real patchwork approach to regulation. I'll have a graph here in a moment we'll look at. That patchwork approach sort of pulls away some momentum. It creates opportunities for us in some ways. It creates obstacles in some ways. You don't have a consensus view or a common approach to how on the policy side of how we're actually trying to drive change. A lot of that, we think opposition to it is just concern about higher energy prices, inflation, the economic consequences of the decisions that are made. For us on the policy side, while you see all the momentum behind some of the mandates and subsidies that are out there is another side to this story. We're not saying that either side of that's winning right now. We would describe the policy environment actually, if you look long term, as being uncertain. It can change. It can change through elections, new politicians, new rules. It can change because of economic cycles. It's uncertain to us exactly what really is the policy momentum. Let's look, when I say patchwork approach, what do I mean? This is the general geography of our refined products pipe. I hope you can see it. It's, you know, the middle third, as Mike described, of the United States. What you see here is that patchwork approach. The green dots that you see on the page are places where we have incentives for biofuels. You'll see states like Minnesota and New Mexico that have a little bit of a red shading. Today, there are biodiesel mandates in those states. Then you'll see the hashes in Colorado, Iowa, and Missouri. Those are markets where they're considering mandates, but they haven't yet passed, similar to the LCFS. In addition to that, before I move on, the blue outlined states, those are all states that have at least mentioned they're considering a Low Carbon Fuel Standard. They're considering a regulatory environment that's very similar to what California, Oregon, and Washington State have in place, but they haven't passed. As I mentioned, New Mexico put it, you know, the bill in place. It didn't pass. Missouri's been talking about a biodiesel mandate. It didn't pass. All of this is not to be dismissive of policy. I'm not being dismissive at all. It's something we have to pay attention to. That's why it's in our framework. There's really not as much consensus as you might otherwise believe, if you really peel back the onion, is the point that I'm trying to make. Let's move on to the next primary force in our framework here, and that's capability. Whatever the policy may be, lack of consensus or not, what are we actually capable of doing? What can we do feasibly? If you look over the last 20 years, it's hard to debate that we haven't made a lot of progress on battery technology, storage technology, solar generation technology, wind generation's becoming more efficient. Things like renewable diesel, sustainable aviation fuel. We've got all these innovations that are happening that are certainly capable, and they're certainly making progress. We have concepts for capturing carbon. Hydrogen's on the horizon. You have all these ideas and capabilities that are being developed. The question is, are they ready for prime time, so to speak? Some are, and some aren't. In some cases, maybe the specific technology we're looking at, say, battery electric vehicles. Let's say you think that is ready for prime time. What about all the supporting infrastructure it takes to actually make them useful? The charging infrastructure, the electric grid, the ability to charge at home, charge wherever you want to charge. I'm not saying that those can't develop or that it won't develop. What I'm saying is, those are pretty significant obstacles that still need to be overcome, just on a technical basis. You have the whole cost equation. They are more expensive. We're trying to handle the more expensive part with subsidies and different incentives to make them less expensive, but even with the subsidies, they're still more expensive. How are consumers gonna relate to that? Part of capability, in our mind, is an ability to scale. It's a cost competitiveness on a fundamental basis. Does that exist? I think China is an interesting example. You may disagree. You know, they're investing heavily in renewables. They're a world leader in EVs. They're also one of the largest investors in incremental coal generation capacity. Think about that for a moment. Increasing investment in EVs, increasing investment in renewables, but it still pales in comparison the investments they're making on the coal side. Why is that? Well, the reality is, I think it's an indication that the capability, what they need from renewables to meet their economic objectives, their societal objectives, it's not ready. Coal is. Rather than not make progress, they're making what progress they can, but at the same time, using the fuels that they can depend on. In their case, it's coal. I think that's an idea when we say capability, what do we mean? Can it stand on its own? Do we have the ability to actually perform reliably the policies that are being put forth? Then the last point I'll make on this in terms of obstacles, you guys read all this, is just the supply chain. Everything has supply chain problems today. If you're trying to buy a TV, it isn't. Good luck. Take that difficulty and multiply it times 10 or 100 when you start talking about the supply chain for electric vehicles. Rare earth minerals, where are they at? When you start putting all that together, again, we're not saying that electric vehicles won't continue to evolve or solar or wind will not continue to grow. I'm not saying that. What we're saying is there are obstacles that are gonna have to be overcome in order to meet some of the policy objectives that are out there. Those are very difficult, and in some cases, systemic obstacles to overcome. Much like policy that we think is uncertain, we really think capability is very uncertain over the long term. Example. On the chart in front of you have. We've chosen four biofuels. On your left is biodiesel, the middle two columns are renewable diesel, and then sustainable aviation fuel, and on the far right is ethanol. If you look in each of these clusters, you'll see the hashed bar. That is the market price of that fuel. That's all it happens to be the market price of that fuel wholesale in California for renewable diesel fuel and SAF in L.A., and then also for the biodiesel. We've chosen a market that essentially has the most incentives available to producers to present this graph. You'll see that if you look at the blue bars, those are the production costs. You'll see in the case of biodiesel, renewable diesel, and sustainable aviation fuel, on a pure fundamental basis, they can't compete in the market with the fuel that exists today. Now, maybe they can scale and eventually be able to do that. The difficulty for scale, I would say, links back to the patchwork nature of what I just described. Today, all these fuels are going to California. All the renewable diesel we can make in this country, plus some, is going to California. Why it's going to California is that's where the subsidies are. That's where the economics exist for the producers to make money making these fuels. When you think about, well, does that mean we're capable? You know, are biofuels ready for prime time? Probably not yet. I mean, technically, they're viable. Renewable diesel is a drop-in replacement for diesel. If we can produce it, then we can get it produced in an economic way and get it to where it's needed. It's a drop-in fuel for diesel today. Sustainable aviation fuel has a bright future, we think, but we've got to find a way to scale this. On their own, they don't exist or can't exist without subsidies. Go back to, if you can remember the slide I had in front of you with the patchwork nature. Where are our opportunities? Mark's gonna talk about some things that we're doing. You know that in biofuels, which is something that we think we are very well situated to handle as the market is interested in them. It's where you're at matters because of these subsidies. Let's move on and talk about what I think is probably the most difficult force to understand of our framework, and one that in a moment when we talk about electric vehicles, I think is really important. This is the most uncertain, it's the most difficult. What I have on the slide here is based on a poll that was done. It's a poll that's been done for a while, actually. It was published in 2021. You may have seen it. It's the API University of Chicago poll about attitudes about climate change and energy transition, essentially. It's sourced. It's noted at the bottom of the page if you wanna look at it. I would encourage you to look at it if you haven't seen it. I pulled from that poll. It was a poll around 5,000 people. These were all folks that made probably over $100,000 a year. It leaned slightly liberal in its polling. These are some attitudes expressed. What does the consumer think about energy transition? Let's start on the left side of the page. 75% of the poll respondents believe climate change is happening. 59% of the respondents said that climate change is very or extremely important. 55% support cleaner energy. 57% support EV incentives, tax incentives, those sorts of things. What's funny, if you read the poll, you will also see that the idea of a mandate on an EV was not popular at all. The idea of incentivizing the use of electric vehicles, but not taking away choice was a really interesting dynamic you should look at. Wildly positive and supportive attitudes toward it, but then you move to the right-hand side of the page. Here's some other attitudes. 80% of the respondents said the economy was extremely important. 52% of the respondents would be willing to pay $1 a month per household in support of climate change reduction. I'm not up here to get into the politics of climate change. I'm just telling you what the poll said, that folks were willing to pay $12 a year to pay for climate change, essentially. On the upper end of that, if you go as high as $75 a month, over a majority, 53% said, "No dice. No, thank you. I don't wanna pay more than $75 a month to combat climate change." This is an interesting dynamic of we sort of have the want, the desire, the belief that what we're talking about is important, but when you get to their pocketbook, the consumer's just saying, "Let's wait a minute. Let's think about this, because while climate change is really important, and it is, the economics, economic growth, my pocketbook, my monthly income is actually more important." How that tension's going to work out is going to be really interesting. Like I said when I started, we don't have all the answers. I'm just trying to present this as a way that we've got a lot of uncertainty even on the consumer side in terms of what are people really going to accept. If the policy wants to do something, we can do it, but it's really expensive. Will consumers pay for it? The poll suggests maybe not. Likely not, even. Those are the three main forces. We have the concept of the external shocks. Again, examples of Ukraine have totally changed the idea of what Europe thinks about energy. Even in the United States, the idea of trying to export as much natural gas to Europe to support them and, you know, sort of helping them not rely on Russian natural gas as much. There's a lot of effort to try and do that, and I think we're going to be able to be successful in that. Even before Ukraine, Europe was really struggling with trying to have a really healthy economy with their energy makeup. You know, they'd moved away from coal, significantly moved away from nuclear power in many states. Not all, in many countries. Not all of them, but many of them. It was creating some real economic issues, real life issues for the population in Europe, and it was not going very well. They're ahead of us, so to speak, in terms of attitudes or things. These external shocks have a way of sneaking up, happening when least expected. When they happen, they change attitudes. They impact this feedback loop, and then all three of these forces have to try and rebalance. Every time it has to rebalance, we think is a little bit of what we would call maybe a hiccup, right? You gotta pause for a minute, figure out where you wanna go, and these external shocks will certainly continue. Economic recessions, the inflation that we're seeing are shocks to the system, and all that is going to impact energy transition. What are the key takeaways we wanna leave you with? Well, first of all, as I started out, energy transition, the concept of conservation has been around in our industry for a very long time. It's going to continue. We expect to continue to see conservation efforts in addressing climate as it makes sense for us to do so. The idea of an energy transition, does it exist or not? It exists. It already existed before two years ago. It already existed. The real question for us is pace. What pace is energy transition going to take? What's the depth? How far does it go? To us, the takeaway is, as we look at energy transition through our framework, it's we think the pace of energy transition will likely be slower than what many people think. Hopefully this discussion gives you a little sense of, "Well, why do you think that?" I hope I've provided enough context where you can kinda see the pluses and the minuses, and many of the three forces we talked about are really uncertain. We think that is going to lead to a slower transition. We also think this transition is gonna be a lot more volatile. If you look out, you know, we're gonna present a bunch of really smooth curves. Everyone else puts these really nice, pretty smooth curves out there. The reality is, it's not going to be that smooth. It's going to ebb, and it's going to flow. Policy's gonna change, and consumers are gonna change, and our capabilities will follow, but it's going to ebb and flow. Slower, more volatile. The destination's unknown. Where are we gonna end up? Nobody knows. We don't know, but we also don't think anyone else knows. The other takeaway is I think the idea that we can ignore the economic impact of the choices that are made, we need to be very careful because what we have learned, at least from this one poll and many others, frankly, and even through time, the economy is most important. If given a choice between a healthy, growing economy and a fatter pocketbook, at least in people's attitudes and minds, they're gonna think twice about policies that really impact that, and they're gonna have to weigh that and determine which of those is most important. With those takeaways, what does that mean we're doing? We know how we're thinking about it, but what are we doing? Well, first of all, I hope you can tell from this presentation we're engaged. We're thinking about this, and we're trying to think about it very deeply. The reason we're trying to think about it very deeply is not only the impact on our underlying business, but what opportunities might it present. There's both sides to this equation. The transition may introduce risk, but it also introduces opportunity. We are doing that in a very complete way. We're not looking at just the policy, what's the government want to see happen, or the agencies, what do they want to see happen? We're looking at it in a very complete and fundamental way. Now don't take that comment to mean that we believe that policy can't create opportunity. We do. We think it can. An example of that is we're putting in a couple of biodiesel blending facilities in the state of Missouri. Well, Missouri, as you might imagine, as I mentioned earlier, actually was thinking about putting in a biodiesel mandate. It didn't pass. In the process, we were able to actually work with the Department of Agriculture to get some investment from the Department of Agriculture to help us fund these facilities to go in to blend biodiesel. It was in their interest, it was in our interest, and it made that a viable project for us to move forward with. Don't take the comments about policy and where it's going or not going to mean that we're not looking at it where opportunities exist, but we have to be very careful 'cause policies can change very quickly. Our investment needs to match, which then leads to the last two points that are really most important. Our approach to energy transition is really no different than the approach we've taken to how we've managed our company for the last 20 years in terms of growth. We look at what we're good at, what we know how to do, what we can learn how to do. We couple that with an understanding of what does it take to win. It's one thing to know how to do something, but you wanna make sure if you're gonna go into something, you have an advantage, you have a reason to be doing it. Because just because you're competent, if you can't win, it's not beneficial. Take what we know how to do. Look for areas where we have advantage and can win. If we find that, make sure the returns that we're earning match the risk that we're taking. That's it. That's the approach. That's how we're thinking about it. We're not ignoring it. Hopefully, this presentation today shows we're not ignoring it. We don't have our head in the sand. We're taking a very disciplined approach to how we approach it. More specifically, some areas where we see advantage. If you have competencies and advantage, where are those, generally speaking? As Mike mentioned in his introduction, one of our greatest advantages, frankly, is just our assets themselves, where they exist, how they operate, their breadth, their scope. We've talked about this in many investor meetings. You know, our system is really interesting in that in the central system at least, you could put a barrel in at Tulsa on a Monday and pull it out in Minnesota the same day. Think about that for a moment as if you're a refiner. You're not just choosing a point-to-point delivery, you're buying a service in many ways from us. Well, that footprint, that ability to operate in that flexible way creates some real opportunities. If you wanna get biodiesels or renewable diesel into the entire mid-continent of the United States. We have the pipe that can do that when the market's ready for it. Not ready today. Saw the patchwork. You can't make money everywhere with it today. When it is, we're ready. Second thing I would mention is on the crude oil side, the fact that we actually control and have custody of crude oil basically from the Permian all the way onto a vessel in Houston. We can do all of that on our own assets. We don't have to depend on other folks. Once we take it in, we can move it all the way onto a vessel. Well, think about in an energy transition world, the advantages that that can create in terms of knowing exactly where that barrel's been, what its carbon footprint is. That's a real advantage for us. We have our terminals on the Gulf Coast, whether it's feedstocks in, exports out, whether it's traditional petroleum products, whether it's biofuels or other products, Gulf Coast presence is an advantage. Our airport connections. We have connections to a lot of the major hubs right here in Houston, both Hobby and Bush Intercontinental. Connections to Love Field, which is a hub for Southwest and Dallas, and our connections up in Denver, which is a major United hub. We've got connections to airports with pipeline capacity that as sustainable aviation fuel is accepted, we're already plumbed up. We're piped. The issue is it's just not economic everywhere. It's economic in California right now, and that's about it. How is that gonna change? We don't know, but we're ready. The last one I'll mention, it's a plug for our commercial team. We really work hard on our customer relationships. You're like, "Yeah, yeah, everyone says that." Well, for us, we really mean it. A lot of ideas and things that we're gonna go pursue, frankly, will be because our customers see opportunities. They see things that they think, "This is a real opportunity for me. And if I'm gonna go after this, I need a midstream partner." That's when they have some choices to make. We're always trying to work to make sure we're choice number one, not just because of our assets, but because they like to do business with us. Those are a major advantage for us. If you take those advantages and you look near term, what's that mean for us? It means we're gonna remain focused on biofuels. You know, I've laid out a lot of facts, and you'd say, "Well, biofuels don't seem like they're going anywhere." We expect them to grow. They're going to become part of the refined products fabric. We don't necessarily know when or exactly where, but they're gonna continue to grow. We're making sure that we're ready as they do. The second near-term opportunity, and this may seem a little odd as well, but as you think about energy transition, the concept of sustainability and ESG, we have a lot of customers that have their own goals, their own things they're trying to achieve in their own businesses that rely on us to provide service, which means their goals, to some extent, they need to know what we're up to, and we need to be able to plug into their ecosystem and be able to report what our own emissions are, how we're handling barrels, and make sure that we're supportive of what our customers need to do. Near term, like the nearest term, those are the areas we're really focused. When you think about things like carbon capture and hydrogen, those are down the road for us. You do have a few projects going on the carbon capture side. They're fairly unique in how they've got off the ground, in my opinion, dealing with ethanol, which takes one of the major obstacles to carbon capture, which is the purity of the actual carbon dioxide you're getting. Ethanol is like the purest there is. It's almost 99% CO2. So you don't have to worry about all the impurities that would come out of a refinery or some other places. So that's a major obstacle. So they're capturing some ethanol CO2 and moving it in a pipe. Hydrogen, we just think is further down the road. Something we wanna make sure we're real clear about, if you look at our pipeline assets, just from a technical basis, they're not really well-situated for either just to sort of repurpose to carbon or repurpose to hydrogen. Some technical reasons for that. On the carbon side, it's primarily an operating pressure, the pressure you have to operate in order to keep the fuel liquid and move it. Then on the hydrogen side, it has to do really with the metallurgy of the pipe and the welds and how it was constructed. Hydrogen's a very difficult molecule to sort of keep contained because it's so small, and it causes a thing called embrittlement in the pipe in its purest form. That creates some issues with this, with our legacy assets. The good news though, is we've demonstrated for many years, we know how to build the assets. We know how to help our customers get from point A to point B, and if it requires new assets to do it, we know how to do that. We also think those markets are just a little further out there. These are advantages we think. These are what we're focused on near term. Longer term, we'll see. For us, carbon capture and hydrogen are likely new build projects for us. We're getting ready to segue a little bit. That was a lot to do about energy transition generally, how we're thinking about it, some advantages we have. Now we're gonna get into some detail about EVs specifically. For us, EVs are probably the most direct mechanism to impact our demand. As you might imagine, we spend a lot of time looking at other people's forecasts for refined fuels, such as WoodMac. Looking at other people's forecasts for electric vehicle adoption, IHS Markit, and many others. In a recent WoodMac report, you guys may have seen it, and I apologize if it's redundant, but I hope I can add a little bit of color to this. This is the logistic S adoption curve. The theory of, you know, when a new technology comes out, what is it? What does the path of adoption look like? You know, it starts on the far left with the early adopters who are gonna try something just because it exists. It moves up to folks that, "Yeah, it exists, but I want it to be, you know, pretty good." It goes all the way to the right side, which are the folks who are gonna hold on to the very end. In between there's a very steep adoption curve between once you sort of get total cost of ownership or price point parity, things can really sort of take off. When I look at this, and I look at the penetration of electric vehicles so far, I still think we're on the left-hand side of that S-curve. I don't think we're even approaching sort of that belly yet. I think we're on the left-hand side of that. The question for us and for everyone becomes, you know, in our business, well, when are you gonna get to that upward slope, that steep slope, and what does it look like? In that same report was this slide. Now I'm gonna get this out of the way first 'cause it will help explain the slide. This slide was created in 1997, all right? The point of the slide is not the currency of the data, it's the shape of the curve and the technologies that it presents. Wood Mackenzie had this in there. That previous page talked about the S-curve in terms of a theoretical S-curve. This is the S-curve of actually things that have happened in the real world, at least as of 1997. When you look at things on the left-hand side like the internet and PC and the mobile phone, they're not at 30% penetration. They're of course, close to 100% today. But what's informational about it is their slope. Look how they start. Let me back up one step. The vertical axis is the percent of penetration into the market, and the horizontal axis is how many years from its invention did the technology take to reach whatever penetration point you got to. Obviously, the internet, mobile phones, PCs, very vertical. Almost immediate adoption. Then you move to something like the television, and the television took between 30, close to 35 years to get to 80% adoption. Then you have electricity, airplanes, and I'm not gonna read all these to you. There's three I really want you to pay attention to. It's the TV, electricity, and automobiles. If the adoption of EVs were to follow these curves, where would that put us? When was the electric vehicle invented? Well, the first electric vehicle, this is kind of one of a fun little fact you can write down, 1832. 1832 is the first electric vehicle. But throw that one out. We're not gonna talk about from 1832, but it was. 1832, we had a battery-powered vehicle in this country. Tesla was founded in 2003. They produced a Roadster in 2008. Let's say the Roadster was the first real example that electric vehicle technology can work. Now it was a niche product. It was a super fast sports car. It was really cool. It sort of demonstrated this could work. Let's use 2008. If we're on the kind of adoption for the electric vehicle that mimics the television, you're looking at 80%-90% adoption in some place between, call it 2045 and 2050 if it follows the TV curve. If it's following the automobile curve, which is 110, you do the same math, 2008 +110 years. Way out in time, 2100. What's interesting is the electricity one, I think. It's kind of between the two at around, you know, 80 years from its invention to its adoption. If you put that on electric vehicles, that puts you at 2080. Which is it? Are EVs closer in terms of resemblance to TVs, electricity or automobiles? What's interesting about the electricity uptake is think about all the infrastructure that needed to be built for electricity to really reach everyone's home. We have a similar sort of problem, maybe different, but it's similar in a sense. We've got a lot of infrastructure that has to come along. I mean, we had a light bulb. You could make it light up. The problem is you couldn't make it light up around the United States. You need it to light up in everyone's home. It's not too different than the problem we have with EVs. We need to charge them at everyone's home, but we have to have the infrastructure to do that. Electricity, we think, is really sort of interesting as a proxy. We don't think the internet, PC, mobile phones, and frankly, even the TV are good corollaries to what the challenges ahead of trying to adopt electric vehicles. That's just our opinion. You may have a different one. There are just too many obstacles, and it's not as simple as just walking down and buying a TV. I mean, for goodness sakes, TVs were like, you know, you went from listening to your favorite baseball team on the radio, which maybe you'd like to do today for nostalgia, but at the time, you could actually, you know, get rid of the radio, buy a TV, and see it. It was mind-blowing. Electricity was basically magic, right? Automobiles essentially opened up the entire United States to anyone that could get a car. question then is, do EVs have those same attributes where the EV is so superior? I'm not gonna debate, is it superior or not superior? I'm really asking, is the order of magnitude. Is it so superior to the technology we have today in its utility that make people wanna run out and buy it at a wide scale? Evidence so far is no. Could that change? Possibly. Evidence so far is no. One of the key drivers to this S-curve is the concept of a relative advantage, a significant relative advantage. Our opinion is that that really doesn't exist. We've got a really good alternative in the car that's sitting in everyone's driveway. It'll do the same thing as an EV. Maybe you have some other considerations in your purchase or what you know what you're trying to achieve, but the reality is we can accomplish what you're trying to accomplish from a transportation perspective with what we have today. With that, as we're modeling EV and looking at other folks' models of EVs, we think, obviously, EVs will continue to represent an increasing share of vehicle sales. Although it's really uncertain what that pace is gonna be and where it's gonna end up. If you look at all the different forecasts for EV sales, they're all over the board. As we're trying to understand EVs, it's pretty important to what we do, right? I mean, if there's a company that needs to become an expert on EVs, not saying we are, but one that needs to become one, if we're not, it's us. There's others in that boat as well. For sure, we need to know what's going on with EVs. We looked at all the other analysts that were out there, all the different curves, all the predictions, and we said, "That's nice, but we're gonna build our own model." We did. We're gonna talk about some of that in just a moment, that I think hopefully will be a little enlightening to you. Before we get into what our model sort of says, here's some just key observations to set the table. Whatever happens with EVs, whatever the adoption curve is, it will be slower in our market area. We may not be right about the United States. It will be slower in our market area because of demographics, and those demographics are not changing very fast. When you look at the utility issues of EVs and what people need and want in our neck of the woods, so to speak, EVs don't meet their lifestyle. Whatever happens, we believe it's gonna happen more slowly in our market area than the United States in general. Second observation. Again, regardless of where you think we're going with EVs, regardless of which forecast you look at, if you look at the next 10 years, there's very much a consensus that refined products demand, gasoline demand is gonna be stable, and it may even increase a little bit, but it's gonna be stable for the next 10 years. Everything we're gonna talk about in a few moments is essentially fast-forwarding out and trying to guess what's gonna happen 10 years from now. Over the shorter term, in our minds, 10 years is kinda short term. In y'all's minds, it may be forever, but it's 10 years. It's gonna be very stable. The last point is, it's gonna take a very long time, and time is our friend. It gives us a lot of time to use our framework, understand what's happening, and adapt our business as we need to. We're gonna talk more about that in a moment, but that is a critical thing that I'm trying to drive home on this slide. Whatever's gonna happen is gonna happen sometime beyond 10 years from now. We can all debate how drastic or not drastic that is, but it's 10 years from now, and we have a lot of time to adjust, and we think we have some very powerful tools to adjust with. Let's take a couple of these just in order. The first one being EVs in operation in the United States. If you look at the United States in totality, there's about 280 million vehicles. It's grown about 6.5% in total since 2016. And if the math's wrong, it's not my fault. It's Aaron's and his team's fault, but the math isn't wrong. That's the good news. But his team's really been working on this. If you take that 283 and you divide it between, you know, our market area, there's, of that 283, 82 million vehicles in our market area. A little over 200 million sort of outside our market area. The number of EVs outside our market area is about 1.25, 1.2 million EVs out of a base of 201. 0.6% of the total. In our market areas, it's under a quarter of. It's 251,000 electric vehicles. You say, "Well, is it really 251?" It is as of this date because we literally have data that shows us every sale by every manufacturer in each county and city that we operate. Yes, it's very accurate. 0.3%. We're half. Whatever the penetration is at this point in the United States, we're half of that. We think that trend is going to continue. When we look at other folks' forecasts, this is a daunting task. As we undertook it, we began to appreciate a little more what, you know, Wood Mackenzie's and the different consultants are trying to do. When we break them down. In a moment, we're gonna get to what our model says. You know, we built our own model, and then we essentially back tested it to the models that we could see from others to kinda get a sense for if you ask some really simple assumptions about EVs, which aren't always clear. I don't know about you all, when you read a demand forecast, it's not always clear exactly what they're assuming for EVs. Hopefully, this will shed a little light on that. It looks like a lot of the forecasts are taking the policies and ignoring everything else and saying, "This is what's going to happen." Unlike our framework that looks at the policies and the consumers and what we can actually do, we think a lot of them are mentioning the capability in the consumer for completeness. When you really look at what's happening, they're just assuming the policies, the automaker commitments actually happen to perfection almost. They ignore the lack of supply, they ignore the grid not being ready, they ignore some of the the utility issues in terms of charging and all that that goes with the electric vehicles. What's also really important is small changes in your adoption rate really move this. You can see the wide variety 50 years out. We're gonna look at 2050. When you get that far out, small little differences can make a very big difference in where you end up. Let's move on to our model. In summary level, what we did was we took the actual data of what the current vehicle fleet in the United States looks like. We took the current fleet of EVs, who sold them, where they're at. We took the age of the fleet in the United States. We looked at how that fleet's going to turn over. We fit the same logistics S curve to it, or one similar to it, and basically pick some points in time. Go out to 2050 to try and understand what the cases are. The first case, the 80% case, the premise of that is it says that 80% of all new vehicle sales in 2050 are EVs. That's the end point of where we're headed in 2050, 80%. The next case assumes 60%, and the next case would be 40%. The percents are rather arbitrary, but they're meant to show the importance or sort of the magnitude of the changes. They're not drastic necessarily. I mean, even in sort of the most optimistic case we're showing here, we're still saying four out of every 10 new vehicles in 2050 are electric vehicles. I mean, that's not a small market percentage. If you look at those cases, and you look at them in terms of time and what it would mean, the chart at the bottom gives you a sense that if the 80% case were to evolve like we think it will, it means that we'll have about 22% of the EVs being sold in 2030, excuse me. In 2050, it's 80%, of course. The year that it crosses over 50% would be 2057. You see the same stats for 2040 and for the 40% case and the 60% case. You can see the timeline quickly gets out. You know, you're extending the time of adoption by decade or longer. If these happen, let's talk about gasoline for a moment. This next slide, on the far left are EV percentage of sales, and there are a couple of things I'd like to highlight. If you look at our 80% case, which is the solid green line, and you look at the blue line, which is WoodMac, they're basically on top of one another. What we've basically been able to say, when you look at WoodMac's vehicle adoption, they're about on our 80% case. 80% of the cars in 2050 are going to be electric. Inside of that on the yellow line is an S&P Global estimate. You see the dashed lines, which are the 60% case and then the 40% case. At the very bottom is a really interesting line. That's the EIA case. That's the case that came out in March of this year, in 2022. If you look at what EIA thinks gonna happen, that's what they think is gonna happen with new vehicle sales. Which is right? We don't know. Couple of words about the EIA. They have not been known to be optimists in most things. They've had a history of really underestimating demand by a pretty wide margin. In this case, they are absolutely the most optimistic case out there, even of the ones that we've shown. If that's the percentage sales in the middle column, what does that mean for what the fleet looks like? If you look in the middle column, this is the number of ICE or traditional hybrids that are in the market. This is the non-electric stock. You know, you're still talking 40, depending on the case, 50% of the stock in 2050 being ICE engines. If you go to the more optimistic cases or pessimistic, depending on your point of view, slower, let's use that word, adoption of EVs, it's obviously much higher. On the far right, what you get is with that adoption and with that fleet in the middle, on the far right, you get what gasoline demand looks like. EIA is pretty much flat gasoline. You have the other curves where it shows that in totality, maybe down 50% in the most pessimistic cases, but it may only be 15% or 25% in 2050, granted. Let's just keep rolling. The next slide. That was the U.S. we were talking about. This next slide is our market area. In the most pessimistic case we presented, the 80% case, which again aligns with WoodMac, is about demand, gasoline demand down about 50% in 2050. The 40% case, you know, we're down less than 25% in 2050. Of course, the 60% case is right in the middle. The key point of this slide, though, is in all cases, we think we're in relative terms significantly better than the United States as a whole. Our market area will be less impacted. Then we have the EIA. On the far left, this is from the EIA March 2022 update. According to the EIA's opinion, in 2050, petroleum fuel will continue to be the dominant fuel driving transportation in 2050 by a very wide margin. In the middle, according to EIA, again, I'm not saying they're right, I'm just referencing what's out there as a point of view. The gasoline engine will still be the dominant engine technology in use in 2050 by a pretty wide margin. If you look on the far right, all that is happening while EVs continue to grow. In other words, what you're saying is we can continue to see EV growth, pretty significant growth from where we are today. as you get all the way out to 2050, because we're starting on such a low base, we're talking 0.3% of the market, 0.6% of the market you can have some pretty rapid growth on a rate basis. When you get out to 2050, may not have near the impact on petroleum demand as everyone may think. Next slide. I'm not trying to. You guys can take this with you. I'm trying to kind of just walk you through logically here and just bring this one little fact at a time. What this slide is total U.S. product demand. We've been talking primarily about gasoline, specifically being down 50%, down 25%, down 15%. This brings in the concept that we don't only move just gasoline, we move distillate fuel, which is, if you think gasoline is hard to replace, wait till you try and replace diesel fuel in terms of where it's used in our economy. It's very difficult. More intractable than gasoline even. Aviation fuel, jet fuel. When you put those three together. Use the gasoline curves that we put there, add distillate and aviation viewpoints to it. This is the curve you get. EIA, the optimists, in pretty much every case, flat for at least the next 10 years, and then that's when things start deviating in terms of how quickly or slowly the pace of energy transition may impact refined products. This is literally happening over a period of time that's almost 30 years in length. The reality of this is where I started, which is, do we have all the answers? No, we don't. We think we have a framework with which we can look at it. When we do our own modeling, we consider others, and we put it all together, we think we're gonna have a really healthy business for a very long time. We're getting to the punch line, I promise, so I appreciate your patience. You know, oftentimes you would come to an investor meeting, you would think, well, you know, viewing uncertainty, and we don't have the answers and things like that, we view very pessimistically and like, well, if you don't have them, we need to find somebody who does kind of mentality, right? Actually, I think that's part of the message here because there's two points that we're gonna talk about on this page. We don't think we have to be exactly right, nor do we have to have all of the answers to know that we're gonna have a pretty bright future and have an opportunity to create a lot of value. Why do I say that? Because I think it's pretty clear that whatever is going to happen is likely to happen over a very long period of time and in our opinion, at a much slower pace even than the post-pessimistic curves we've already shown you. Even if we take the most pessimistic curve that we've shown you today, that's only half, maybe a third of the story. It's volume times rate equals revenue. We spent this whole time talking about volume. That's what we're all focused on. That's what the market's focused on. We haven't talked yet about rate. Mark Roles will get into that in a little bit. When you look at our business and where it is, we think we're going to have the ability, if necessary, to raise rates to maintain profitability and financial health. I think that is maybe underappreciated by many that look at our company. They look at the volume and say, "Oh, the world's gonna be terrible," and they never really think about what we can do with rate. I wanna kinda break down why we think that rate is something that's a viable tool for us. First, even in the most pessimistic scenario, we're still moving at least half of the fuel in 2050 that we're moving today. That doesn't sound great, but it's still half. If we're gonna move half of the amount of fuel that we're moving in 2050 that we're moving today, the most efficient, safest, reliable, and frankly, carbon, you know, lowest carbon-intensive way of moving that fuel where it's needed is a pipeline. It's not rail, it's not truck, it's not. It's pipelines. We're gonna be needed. Our assets are gonna be needed. Mike mentioned at the very beginning that, you know, we have essential assets, critical assets. That's really what we mean. As long as people need petroleum in this country, they will want to use our pipelines to do it because it's the best choice. The question becomes, okay, say you believe that. You say, "All right. Yeah, Aaron, I believe that pipelines are the best choice, but can you actually do it economically?" We believe the answer to that is yes, and the reason we think we can do that is because of our ability to raise rates. It's through our regulatory structure that's sort of built in and how we do that to track cost per barrel mile. As volumes decline, we should have the ability to increase rates to offset. If you look at our revenue model, we're actually increasing revenue, but we have a pretty high operating margin generally, which actually means there's a potential for margin expansion in that environment. You put those two together, even in the most pessimistic view, we've got a very robust economic proposition for a very long time. We have a sustainable business proposition, and the pipes are very sustainable, low emissions transportation. If you look at the rate or the range of rates, you're saying, "Well, that's great, but what, you know, what would the rate need to be in order for that to sort of all work out?" Well, if you pick a more pessimistic case, if we're increasing rates in the 4%-6% range, we're gonna have expanding margins and continued profitability, and most importantly, cash flow generation all the way to 2050. I don't know about you, 4%-6% fits right into some of our recent rate increases. They're not out of whack, so to speak. Give you a sense, you know, our tariff today represents about $0.04 per gallon at the pump. Double our rates, and it's $0.08. Think about that. On top of that, put the really almost irreplaceable nature of many of our assets on top of that, and it's a very powerful economic proposition that we have. We think that's underappreciated. We've got 35 years. You know, some will say if you look at this on paper without having the sort of overlay of the conversation like, "This doesn't make me feel very good. There's a lot of curves and, you know, sort of downward sloping." Hopefully, they read the transcript to go with it, right? Or we haven't done a very good job. The point is, just pick the pessimistic case, and we still have a very optimistic story when you look at the actual economics of what we think we're gonna be able to do. I'm coming to an end. I'm sure you guys have some questions about the next part of the slide. We're gonna segue a little bit. We've talked about the adaptability rate being one of those areas where we can adapt. Now let's just talk about value. In the chart, the blue dot represents our view of value of this company. Yes, there's not a value there on purpose for those that are wondering, "Are you gonna tell me what your fair value is?" I'm gonna try very hard not to. That's where it is. That's the dot. It's straight down the middle. You know, we're known for being a fairly conservative company. In the back of your slide, you'll see some estimates on WACC. We're assuming our crude business remains very stable. In this particular analysis, we're not even increasing our rates at the bottom end of the rate that we could if one of the pessimistic cases happens. We're being conservative. We're increasing them less than that, frankly. That blue dot, the most pessimistic case, is comfortably above our recent trading range. When we look at the world, you're like, you know, we've, you know, bought back 800 million units, and we say we do that because we see value. It's this blue dot. There's a gap between where we've been trading and that blue dot. There's value there. Again, the most pessimistic case that we've shown you, at least in our region. Now let's assume less pessimistic cases. From zero, what's the upside potential? If we're partly right, and this is slower, we're better able to adapt, and people think we can move, what does that mean? We think if you go all the way to, like, the EIA case, you know, the eternal optimists at the EIA, we think there's $20 a barrel, ballpark, of upside. We're feeling pretty good about where we're at, where our business is going, in terms of what we're going to be able to deliver. We think there's inherent value in where we're at today, hence the behavior that we've had in terms of buying back units. We're doing that because it makes sense for us to do. We see value, and we know our own business way better than we know a lot of other businesses. I'm going to move on and try and put a bow around the last hour and 15 minutes or so. That bow is this page. Our services are gonna be needed in 2050. There's no doubt about it in our minds, and we have the tools and the amount of time that we need to make sure we're healthy and we can adapt and create value for our unit holders. Pipeline transportation is sustainable transportation. We are a sustainable business. How we operate, what we operate, the carbon emissions of what we do are sustainable, better than rail. If you think about this today, all the renewable diesel is going to California. How's it getting there? It's getting there by rail and ships, for the most part. We can beat rail and ships over long distances for fuel all day long on a carbon intensity basis. That's an opportunity for us long term. We are sustainable. We have time to adapt. When you look at our value proposition, we've got a lot of things to offer. Not only do we see value if the transition's slower than just today, even in the most pessimistic case. If it's better than that pessimistic case, there's a lot of value to create just on the capital return side. Let's not forget that all along the way, we're sending checks out. Cash on the barrel head every quarter. Regardless of where we end up in 2050, all along the way, we're gonna have the kind of company that's just gonna continue to put money out there on a current basis, and we think we're actually really well poised to see some capital appreciation if, as we think, energy transition is slower than what many people think it will be. You guys have been so patient and pretty attentive too at this early in the morning. I appreciate that. That's the end of my prepared comments. As Paula mentioned, we are planning to take questions at the end of each section. You were kind enough to listen to me drone on and on here for about an hour. What questions do you have? Shoot. You might wait for a mic just so everyone can hear it, if you don't mind. Sure. Is this on? All right. I guess it's the view that 10 years from now, 15 years from now, you'll say our volumes will be down 2% this year, let's raise rates 3%. Is it that simple, or is there a more elaborate mechanism that kind of needs to happen in order to achieve those rate increases? You know, in the grand scheme of things, I think it can be that simple in many of our markets. Now, Mark's gonna talk about this and it'll bring us home, so I'm just gonna touch on a moment. You know, we do have a regulatory environment that we have to operate within. You know, roughly 30% of our markets are indexed rates. They're less competitive. We have an index that we must follow in those markets. The other 70% of our markets are market-based. So what we have to do is look at where the competition is, where are we, what's the value proposition. We, you know, it's not like we have unbounded power to do whatever it is that we want to do. These markets, we have competitors. Within that context, we do have the ability to adjust rates as we see fit. Does that answer your question? Yeah, I guess I'm just trying to look for how simple it truly is to get that pricing power. So if there is a demand destruction 20 years from now, and you do have competitors, I guess how do you maintain that pricing power for a smaller pie, if you will? It's a really good question. Let's say we are at 50% of demand in 2050. Just pick your year, whatever it is. There's competitors, and we're all trying to get a shrinking pool. Well, I think that's where the nature of our business really kicks in, and you start seeing how differentiated it is. I mean, if you have a competitor, and they're trying to compete with us to move from point A to point B, that's one thing. If you really think about what a competitor has to compete with, it's not from moving point A to point B, it's moving to point A or B, C, D, E, F or G in an instantaneous moment. If you wanna be able to do that, at least within the central system, you have to replicate all that. We think there's a pretty wide moat that, yeah, there'll be competition in there, but we think it's gonna be more localized and not the kind that really threatens the franchise over a long period of time. If you just look at our history, Mark will have a slide that'll come up here in a little bit that shows our history of rate increases, and I think you're gonna show it on this upward trend of rate increases over 25 years. I think we've got some sort of evidence that shows that we have this tool that we think we need to have. It may change, and we also think we have an asset base that keeps that moat or that differentiation at a level where it'll be a really viable tool for us. Did I answer your question? Yeah. Why don't we start? We'll go over here first and then that lets you catch up over here. Gabe Moreen at Mizuho. Aaron, thanks for the presentation on the renewables and whatnot and EVs. I just wanted to ask about, you know, the hallmark for Magellan's management team has been discipline for so long. I've always taken that to mean cash returns right now on investments. I'm curious in the context of making investments in energy transition, whether it's those biodiesel blending facilities you mentioned in Missouri, more of what you're looking at. Have you passed on certain investments either because there's an uncertainty and a longer-dated nature to some of those investments or because you're uncertain about the subsidies? I guess will the approach change at all, or do you see the approach changing at all over time? It's a very good question. You know, we think discipline, that's not going to change. When we think discipline, what we really think is discipline and approach. The way we look at things, how we evaluate them, it's a process that we use, and we apply that same discipline process to energy transition. It may change, you know, we wanna make sure we're not leaving any stones unturned to what opportunities may be for us. Again, it goes back to what we know how to do and where we think we can get an advantage. You know, we took a cursory flyby of the solar space, didn't like what we saw. We took a cursory flyby of the wind farm space, didn't like what we saw. We didn't think the returns and risk matched. We're probably late to both of those games, frankly, but we just didn't see anything that really fit what we were gonna do. On the biodiesel, it's blending. Frankly, the only way that the blending investments that we needed to make in Missouri that we were making, the only way they made sense was with the help from the Department of Agriculture. Had they not shown up with part of the amount to invest, we probably wouldn't have been putting blending there in either. Your question about have we passed on things, we've passed on a lot of things because we just don't see the risk-return profile making sense. Now, that's probably not gonna last forever. At some point, we're gonna find some opportunities where we're gonna get that intersection of risk and reward, and we'll be able to invest more. Until we get there, we're generating a lot of cash flow, and we can return a lot of that to unitholders until we get there. We think this is gonna be a cycle. It's gonna ebb and flow. Nothing's permanent. You know, don't extrapolate the lows, don't extrapolate the highs. Neither one of those end up being right. It's gonna be a little more cyclical. What we're passing on are things that don't show the risk return or they don't match our competency, but we're continuing to look at where it goes. Go ahead. If I could follow up with one on that, Aaron. Just in terms of what Magellan's approach is to what you would like to see from a policy standpoint, whether it's at the federal level or the state level, I don't mean to put you or Bruce on the spot here. Whether it's pricing out carbon LCFS standards at different state levels, how involved is Magellan currently in trying to get some of these things done? Well, I think Bruce is a frequent flyer on about every airline in the United States. He's on the road a lot meeting with states and, quite frankly, cities and the federal government. What would we like to see? Well, I think from our perspective, we just need to have some clarity as much as we can get. We need some consistency, some clarity, some principle to the policies that are being put out there, and less rhetoric or policies that just change with the wind. You know, you can deal with a policy once it you understand what that policy is, what it's encouraging, what it's not encouraging, where it's leading us. You can deal with almost all of that. It's when it's shifting all the time or when it's different in different geographies, that's where it's really difficult to operate. From my perspective, the simplest thing we would ask for is just a well-thought-out, and therefore consistent policy, around energy transition. Whether that ends up being a carbon tax, we can debate a long time whether we think that makes sense or not, and I don't wanna do that up here. I think there are some scenarios, and some in the industry actually support the idea of a federal carbon tax. Politically, it's a non-starter. Even if they put one in place, if it were in place and it were thoughtful and it were consistent, you can operate. Right now, we just don't even know what to do, frankly. Did that answer your question? Thanks, man. Give me a couple of minutes. Bruce, would you add anything to that? I mean, it's set up just for you. Okay. Testing. Hi, this is Praneeth, Wells Fargo. If we assume inflation goes back into the 2% range, which I know is a big if at this point, but if we assume that happens, do you still think you'll be able to raise rates at the 4%-5% range across all your pipes? Do you think the FERC index adjuster needs to kind of increase over time to support that range, or how do you think about that? If you go look at it, you know, we've got periods of time where at least in the market-based. Again, you have to look at indexed versus market-based. The indexed are gonna be the indexed, right? So it's inflation plus every five years, the FERC decides what the adder is going to be. And then we have the market-based rates. And we've shown a long history, even when inflation was 1.8%-2%, of increasing at well more than just inflation in our markets, even our market-based market. So we've got a history of being able to do it. Now, will that change? Maybe, maybe not. this is when I go back to sort of the fundamentals of our business, where I think we've got a lot of really strong fundamentals and sort of differentiation in our services that gives us some of that or allows us to increase those rates. I mean, at the end of the day, though, we have to create value for our customers, which we think we can do. We don't think it's out of the question for sure. Hi, Aaron. This is Theresa Chen from Barclays. Yes. I wanted to ask you to expound a bit more on your views on the New Mexico LCFS market or the program. Do you think that this is something that can cross the finishing line sooner than later, or do you think there are still meaningful hurdles to it? Given your refined products footprint towards that area, if it does go through, would you be able to ship renewable diesel to those markets, given that it's a drop-in fuel? If so, would that garner a higher rate potentially? It's an interesting question. At least the LCFS, at least my understanding, Bruce, correct me if I'm wrong, but the LCFS, at least as of this year in New Mexico, is dead. Now, can it come back in the next legislature in New Mexico? Sure. As of right now, it's dead. Why is it dead? It's dead because the politicians did not want to be anywhere near the blame for higher energy costs. I mean, that's what killed it. They were convinced that LCFS, when they look at everywhere else it's been put in, it raises the cost of gasoline and energy for the consumers. They're not gonna have it. You know, you've got all the other things going on right now, but that was the primary reason. It is dead as of right now. Now, let's move into hypothetical land, and let's say that one existed. While we're not there today, you know, we think long term that the potential to move renewable diesel from the Gulf Coast across our refined products in Texas and then up into New Mexico, pretty promising, frankly. I would say it's about the market developing in a way where it's needed, and then you have to get the supply, obviously, on the origin side. But if you look at where a lot of the growth in renewable diesel is happening on the production side, it's in the Gulf Coast. As that market develops, we think there's actually a really good opportunity for us to move renewable diesel. It doesn't mean necessarily our volumes are going to grow, but it also doesn't, it means they're not gonna decline if we can get that fuel into the market. We think there is a good opportunity to do that. Sorry, just on the rate itself, would that garner a higher rate given that it isn't renewable fuel? Or do you typically charge at the prevailing, you know, petroleum diesel rate? It's typically the same charge. But if we have to do any special handling, in other words, depending on how it's put in and how the LCFS market works, it may be more expensive for folks to move it. But it's still gonna be way cheaper than rail. Any other questions? All right. You guys are ready for a break. First of all, thanks for being here. Second of all, thanks for listening to me drone on for an hour about energy transition. A lot of that I'm sure you guys have seen. What I hope is that our perspective of it was useful to you and helpful. Hopefully you're walking away with here while you may pull the book out a couple of days from now and say, "Those are really pessimistic charts." You'll remember those are volume charts. When you look at the business, we're actually very optimistic, and that's the point we're trying to make. Thank you. We're gonna have a, I think, a 15-minute break. We're gonna come back, and Mark Roles is gonna lead us through our Refined Products segment. 15 minutes. It's now five after, so come back at 10 till. Thank you all very much. Welcome aboard the Disney Bundle. We're gonna go ahead and get started here in just a minute. If everyone take their seats. Okay, right on time. I'm gonna dive into more in depth on the refined products business. My name is Mark Roles. I'm Senior Vice President of Commercial Refined Products at Magellan. I'm probably a new face to a lot of you in the room. Hope to meet you more personally soon. But I'm not new to Magellan or to the refined products business. As Mike mentioned early on, everyone speaking today has spent our entire career here at Magellan. For me, 22 years, 19 of those in the refined products business. Aaron talked about energy transition and a lot of interesting perspectives that Magellan holds on that front. He also talked about EV penetration, what we might look like down the road, even out to 2050. I'm gonna get into a little bit more depth about the refined products business, and really, there's gonna be four themes you're gonna hear in my discussion today. Number one, Mike mentioned this early, Aaron mentioned it again, but we do have critical assets. I'm gonna take a little bit of different approach, though, and explain why those are critical to our customers and to the markets we serve, and give you some specific details and examples of why that might be. The second theme is really macro market dynamics that are going on in the United States today on product flows between PADDs in the U.S. If you're not familiar with PADDs, those are Petroleum Administration for Defense Districts as defined by the federal government. I have a map later that will show you the details on what makes up the different PADDs in the U.S. Those product flows, how they influence supply and demand in the U.S., and it really has a large impact, especially when you think about the footprint of Magellan's business and where we sit, where our assets sit. Third is really the largest components. I'm gonna go through each of the largest components that create value for Magellan's refined products business. Those are transportation being the largest, storage, our commodities business, and then lastly, renewable fuels, which is a much smaller piece of our business, but we see that as a growth opportunity, as Aaron mentioned. The slide you have up in front of you is a map of our system. All of you have seen this before. What I'm gonna do is walk you through how this system operates at a very high level, but it illustrates some of the really important points. It's largely a demand-driven system. However, we're also connecting very dislocated markets in some cases, and you're gonna hear about some growth projects later on that we're working on right now, that illustrate that dislocation of products, certain shorts in markets that we can meet. We're connected to roughly 50% of the refining capacity in the U.S. in total. Pretty much everything in Texas City and in Houston and Port Arthur, either directly or indirectly through third-party pipelines, as well as all the refineries around the Midwest, into Denver, and of course, West Texas. Our central system. When you think about our central system as you look at the map, that's really Oklahoma and Arkansas North. That's what we consider our central system, and this is what's known as an open stock system. Open stock isn't something new to the industry, but it's pretty unique for the refined products business. Our system, the reason why we can do this is because it's more of a hub and spoke type system. We have refineries dotted throughout our footprint, and we distribute from there multiple directions on our system. What open stock really means is that a customer has a pool of, for example, gasoline in our system or diesel fuel or jet fuel. When the barrels are delivered into our system, the physical molecule and the paper molecule, the paper separate. For example, Aaron gave one example of this earlier, I'm gonna illustrate it even further. A shipper can buy a 25,000-barrel batch, for example, in Tulsa, Oklahoma, deliver it into our system. Once it's ticketed in, they now have a paper inventory of 25,000 barrels in our system. They can immediately paper that to Des Moines, Iowa, for example. We generate the tariff from Tulsa to Des Moines. Magellan, behind the scenes, physically delivers that barrel from a different refinery origin that is more efficient, a shorter distance, so it costs us less to move it there. That's one example. There's many examples of like that. We also have customers. It's really a trade hub in the Midwest called Group Three, where customers product transfer or barrels around our system all the time, every single day, where they're buying and selling, moving barrels. We also have the ability to float between larger markets like the Gulf Coast and Group Three. We can paper barrels back and forth to balance out those markets. That central system is really. I was talking to one gentleman earlier. That's really what differentiates Magellan from our competitors in those markets. You might have a competitor that has a you know, one or two refinery connections that comes right into the heart of our system and competes with us, but they don't have access to all those markets that we have access to. That's where we differentiate ourselves in that Midwest system. When you look at our mountain system, which is really Kansas and into Colorado, and then we also have origins from the north out of Montana and Wyoming down into the Denver area, that's more of a transit time system, meaning customers have to wait a period of time once those barrels enter the system before they can have access to it at our truck racks. Our Texas system operates kind of a hybrid of that, where it's somewhat pseudo-open stock. When you think about those systems, though, we are in premium markets. Like for example, West Texas, Dallas-Fort Worth, the New Mexico markets and the Colorado markets. I'm gonna get into more specifically why those are premium markets for us. Then also in the Gulf Coast, and we didn't have any specific slides on this today, but we do have two very large, critical marine facilities on the Houston Ship Channel, our Galena Park terminal and our Pasadena terminals. They have five ship docks, multiple barge docks. We do many volumes and different grades of imports, exports. We're also connected to almost every refinery in the region, in the Houston area. Those are also origin points for our pipeline system, as well as Colonial Pipeline and Plantation Pipeline systems. I know we've had a lot of discussion about demand and what's happened in our market area over the recent past. This is a chart that shows the last 21 years or so of demand for gasoline as the green section. That includes the ethanol piece as well, and then diesel fuel and jet fuel. Really what this illustrates is what we've been talking about for most of the day, and that's the resiliency of demand in our market areas. This specific data is from PADDs 2, 3, and 4, which are the PADDs that we operate in. They do not include PADD 1 and 5. I wanna point out two specific areas. It's really the 2008, 2009 period, the great recession, where there was obviously a dip in demand, but it recovered fairly quickly. Really 2017, 2018, you see the uptick. That's really in PADD 3, really the drilling in West Texas that's driven that drove a lot of that growth. Of course, the pandemic, where the economy pretty much shut down, as you all know, through 2020, and you still see pretty robust demand in our market areas, and then obviously the swift recovery into 2021. The next slide shows our system specific. These are transportation volumes over the last three years on our system, so these do not include renewable fuels. To include that, it's roughly 10% of that gasoline piece on this chart. Diesel demand overall since the pandemic recovered very quickly. In fact, you probably see on the chart it's actually grown. That's mainly because of our Texas expansion projects that we completed in 2021. Gasoline and jet fuel have been slower to recover. Mike shared a lot of this when we gave guidance in February. Gasoline this year going into 2022, we expect approximately 4% overall growth from 2021. That's 4% higher gasoline, 2% higher diesel, and 15% jet fuel. I can tell you know, part almost all the way through the first quarter at this point in 2022, we're right on track for that at this point. I would see nothing that would change that forecast at the moment. For sensitivity purposes, and again, Mike shared this in guidance, when we issued that in February. Approximately 1% change in refined products transportation volumes represents about $10 million in DCF annually, just for modeling purposes. What's our focus right now? It's capturing market share, enhancing our services through new projects, and I'm gonna get into three or four examples of that here in just a minute. New technology is something we haven't talked about today. Magellan is spending a considerable amount of resources, time, and money on enhancing our technology and improving how our customers view our systems from a systems perspective. As an example of that, we're doing things like APIs with our customers now where data is being transferred immediately back and forth between our customers and us. Really reducing their back office costs, enhancing the value of Magellan. Of course, Aaron mentioned customer service. We hear that on a very regular basis from our customers that Magellan is top of that chain in our industry. Some examples of that are our creativity commercially at Magellan, as well as Aaron mentioned this on the operations front. We have very reliable assets. Our operations and asset integrity teams do a great job of keeping our systems operating. Even when we do have a small incident, we're very quick to recover, and obviously that's critically important to our customers. Effective pricing structures, which we've talked about a little bit, and I'm gonna get into a little bit more detail here in a few slides. Just, I wanna go back to this slide one more time. When you think about the medium-term demand, you know, Aaron talked about, and we saw the chart of all the consultants in EIA going all the way out to 2050. In our view right now, we're still in recovery mode, and we should see ourselves back to that 2019, 2018 range later on this year, and maybe even exceed that at some point. We see that growing over the next couple years and eventually, you know, flattening out. One thing consistent on the slide that Aaron showed is that over the next 10 years, there's really not a lot of discrepancy between those consultants. We see very robust demand. In fact, if you can compare the data, for example, with IHS Markit, comparing demand in our market areas from 2021 - 2030, there's actually a slight increase in demand for gasoline, diesel fuel, and jet fuel in our regions. Our view at this point is that we're gonna see very robust demand for refined products in our system, for the very long foreseeable future. This slide, they say a picture is worth 1,000 words. This one we could talk about all day long. I have five minutes to do it, so I'm gonna do it very briefly. These are the PADDs districts I was talking about earlier. It's how the U.S. looks at flows and supply and demand for products in our system. A lot of the EIA data is split up by PADDs districts. I'm gonna walk through this very briefly, but just some definitions first. The arrows are representing product flows on pipelines, and I'll give you some specific examples of actual pipelines that are creating that flow, and then, of course, exports. On the supply side of that equation for each PADDs, that's refinery operable capacity in that region, and we've seen some rationalization here recently that I'll get into on the next slide here in just a minute. On the demand side, it's gasoline, diesel fuel, jet fuel, and renewable fuels, actual consumption for 2021, okay? A couple important points on this slide are PADD 3 really has the significant length that everyone knows about. It's around 50% of the U.S. refining capacity is in PADD 3. That's where the majority of the exports go out of the U.S. for refined products. That length really supplies by pipeline all the other PADDs in some form or another. For example, PADD 1 is structurally short. A lot of refineries have shut down over the last 20 years. two more in the last three years. Those are mainly supplied by Colonial Pipeline and Kinder Morgan's East Pipeline through the Gulf Coast. For various reasons, the economics on the East Coast running refineries and the fact that their crude is based on Brent price versus WTI has a big impact on that. The efficient mode of transportation on Colonial and Plantation, or excuse me, Kinder Morgan system, to compete in those markets is very strong. PADD 2, our largest operating area, is fairly balanced on paper. There are inter-PADD dynamics going on here, though. For example, in our northern region, in the Minnesota area and even over in Chicago, those are structurally long. The refineries in those areas have expanded over the last few years, and that's pushing barrels further into the PADD, for supply. That's creating long-haul opportunities for our pipeline system. Another example of an inter-PADD dynamic is in PADD 4, where again, overall that PADD's pretty balanced. However, on the Front Range, the Colorado Front Range, it's structurally short, and that was driven by, it was already a tight market, but then HollyFrontier shut down their Cheyenne refinery to convert to renewable diesel, and that took 50,000 barrels a day, right off the supply side, of that market. Of course, we have two of the major pipelines supplying that area, two of the five supplying that area, so we've been able to expand into that market in a pretty significant way. You move over to PADD 5, which is really the story I'm getting to. PADD 5 is structurally short today, slightly. There's been two announced conversions to renewable diesel. We're likely to see more happen in PADD 5. The environment for operating refineries in California specifically is challenging. We see this possibility of that becoming more short here in the near term, you know, the next 2-10 years timeframe. The reason why that's important, we don't operate in that PADD, obviously. However, they're all interconnected by pipelines. For example, PADD 4 is connected through the UNEV pipeline to PADD 5 and the CALNEV pipeline that comes from L.A., and they both meet in Las Vegas. That's kind of the balancing point between PADD 4 and PADD 5. Our system is the balancing point between PADD 2 and PADD 4. We're also the balancing point between the Gulf Coast and moving into El Paso because we're connected to Kinder Morgan's system that delivers over into Arizona. Kinder Morgan's system comes from both directions and meets in Phoenix. That's the balancing point between those PADDs. The point is our view is that over time, and it's happening today, and you're gonna see with our projects that we've been working on, this phenomenon is happening today, where movement is moving further west across our system. The reason why that's important is because Magellan sits smack dab in the middle of that opportunity. We have access between PADD 2 and PADD 4. We have access between PADD 3 and PADD 5, and we're in a very good position to take advantage of that over time. There's really 5 big opportunities. That north PADD 2 that I mentioned earlier, getting long-haul movements into our system further south, that's gonna be there for a long time. Even if demand drops over time, that refinery, those refineries in the north are gonna push further south. They have access to inexpensive crude from Canada. They've been very competitive in doing this. The Colorado Front Range, which I mentioned earlier, that's a huge opportunity for us. These aren't massive projects, but they're very good returning projects, as I'll walk through here in just a sec. West Texas, the growth in the Permian Basin, there's been a refinery rationalization out in New Mexico that's influenced supply in that market. That's a big area of opportunity. New Mexico is another big opportunity. Of course, exports. We have two major pipelines that are connected into Mexico in our El Paso market. We also, as I mentioned earlier, we have five ship docks on the Houston Ship Channel. We're very well positioned to meet these opportunities. This is refinery rationalization that's occurred over the last 3 years in the U.S. There's a couple important ones that I wanna mention. First, the HollyFrontier Cheyenne Refinery that shut down in 2020. They're converting that to renewable diesel. Those barrels, until something else changes structurally, from a regulatory perspective, those barrels will be railed to California more than likely. That immediately took 50,000 barrels a day off of the market, the supply market on the Front Range. Of course, we have two of the major pipelines flowing into that market, created a structural short. We also have the only connection in the Denver International Airport, one of the top five highest volume airports in the country. It created opportunity for us, and we are expanding those systems as we speak. Another one is in New Mexico, where we saw the Marathon refinery out there. It was a small refinery, 27,000 or 30,000 barrels a day in Gallup, New Mexico, shut down. That created opportunity for us to expand our New Mexico system that runs from El Paso up into Albuquerque and hits a railroad feeding depot partway up. Those are examples of, you know, rationalization, partly driven by environmental regulation and partly driven by energy transition, but they created opportunities on the transportation front of our systems. The West Coast, we've seen two conversions at this point. One is underway right now. That's the Marathon project in Martinez. Phillips 66 also announced at their Rodeo refinery, they're gonna be converting that. That refinery is still operating today, but they're expecting by 2023 for that to convert over to renewable diesel. When those conversions happen from a traditional refinery, what we're finding is that they're not continuing to operate the original refinery. That leads us to some expansion projects that we've been working on. You know, the rationalization, the product flows between PADDs, they tell a story, and it set us up with the breadth of our system in the Midwest, our access to those markets, like in Colorado and West Texas, it sets us up for opportunities. The first one is really our Kansas-Colorado system. And admittedly, you know, we've talked about these projects in the past. They're not huge capital projects, but again, they're very good returning projects. And all of them that we've approved to date have been committed on long-term commitments by creditworthy customers. The first one is a 5,000 b/d expansion on that Kansas-Colorado system. We completed that in 2020. Again, we're still on allocation on that system. We believe in the market. We believe it's short structurally today. Late last year, we went out on a second open season on that system, and we had multiple customers commit long-term commitments on the next portion of that expansion, which is another roughly five a day. That would be complete by the end of this year, roughly. We're very excited about that. These are opportunities where, again, the market's short. We have proven that by going on an open season and seeing huge demand from our customers. Also, when we did that open season, we also had put premiums on those tariffs compared to our base tariff, and were successful in doing so. Again, very good returning projects from creditworthy customers that have committed long-term commitments. New Mexico expansion, again, it was a small. These are hydraulic expansions, if you will, either converting pumps, adding pumps, or adding drag-reducing agent into those pipelines. They're very capital efficient. The New Mexico system is an example of that, where we are converting some pumps, adding about five b/d of capacity. This is only a 25,000 b/d capacity pipeline. You know, we're going up slightly north of 30,000 b/d, but again, committed by a long-term customer. The projects that we've approved, those ones that I just walked through, all are on the lower end or even better returning than our six to eight EBITDA multiple type projects that we've targeted in the past. Some potential further expansion. I talked about the structure in the state of Texas and in New Mexico, further into Arizona and New Mexico. We have another hydraulic expansion that we can do on our Texas system. If you remember, back over the last three years, we spent about $1.2 billion expanding our Texas systems for refined products. Those expansion projects are operating very well, as expected. Those projects expanded our ability to move more barrels out of our East Houston facility and the Gulf Coast into the central part of Texas, into Dallas-Fort Worth, and into West Texas. Expanded all three of those areas. All of them are operating as we expected. What we have now is a bottleneck between West Texas and El Paso. This next project will be, we likely will go out on open season here in the next month on that project to gauge customer interest. Assuming we get good customer interest, which we expect, we'll likely approve that project. We do have other opportunities to expand into those markets longer term, but we're taking these one step at a time, and again, trying to achieve that six to eight EBITDA multiple or better, on those projects. Pretty good opportunities. All in, you know, the projects we've approved, it's around $40 million in capital, so it's not gonna, you know, it's not gonna change things dramatically from Magellan or our investors. However, these are really good returning projects. As we see these incremental opportunities. Even in a downward cycle in our market, that's pretty encouraging. We're starting to see customers really reengage with us at this point on new opportunities. It's pretty encouraging. The Texas expansion, you know, it'll be somewhere in that same range, you know, probably $20 million-$30 million in capital. But again, a very good returning type project. It's gonna be about 12-18 months to complete that. We have to build some storage along with that, so that takes a little bit of time. Now I'm gonna talk about rates and how we set our tariffs at Magellan and how we view this. Aaron talked a little bit about this. About 70% of our revenue for refined products is generated through our tariffs. I think in 2021, it was about $931 million, somewhere in that range. Those are just tariff-based revenues. So our tariffs are split up really between two different structures. Aaron talked about this when he answered some questions earlier. Our market-based, which means that we're deemed by the FERC to be workably competitive. Those are competitive markets. Our index markets, which are deemed less competitive and typically follow the FERC index. I'll get it on the next slide in more detail on the FERC index and how that's set and how we view it. On the market-based areas of our system, we go through a pretty extensive year-round process where we are evaluating every specific market. We're looking at customer demand into those markets. We're looking at the competing pipelines. What kind of pipelines are those? Are they integrated type companies or are they third-party type companies that we're directly competing against? We look at all those dynamics in every single market, and we're pulling a lot of data, some public, some of our institutional knowledge of those markets, and we're putting an equation together. Ultimately, what we're trying to do in every single market, in the market-based markets, are trying to find that equilibrium of our ability to set rates at a particular level and also keep market share where we want it. That's a balancing act. Sometimes we'll decide to hold rates a little bit lower if we feel like we're losing market share to a competitor. Other times, we'll be able to ramp it up because we're gaining market share and we have a competitive advantage. When we look at this, we talked about it earlier about how we increase rates and how we see that long term, you know, our view is that we have a competitive advantage. I talked about that earlier on, you know, the breadth of our system, the fact that it's open stock, the fact that a customer can deliver barrels into our system and hit 40 different markets versus one or two. That is a huge competitive advantage, and it gives us an opportunity to be able to increase rates over time. A little bit about the FERC index. If you look at the chart, this is a chart that Aaron referenced earlier. The index rates, since its inception in 1995, have increased about 2.8% cumulative average growth rate. That's on the index markets. On the market-based markets, if you look back at that same inception of Magellan's adjustments, that's about 3.7% CAGR during that same period. As you're looking forward, you know, in recent years on the market-based piece, we've been a little bit more aggressive, and I shared the reasons why we're able to do that. On the index markets, we really just follow the index, which we're required to do. FERC sets every five years their index, and it's PPI finished goods plus or minus an adjustment. They're using cost per barrel mile, and they're incorporating long-term demand to establish those. The FERC goes through a pretty extensive process where they're taking you know the FERC Form No. Six a nd the data associated with that on page 700 from every midstream player, and they're using that data to establish these adjustments. In 2021, the FERC set an adjustment of PPI for finished goods + 0.78. Mike shared all this in guidance, but I'm reiterating it here. Upon rehearing, the FERC readjusted that to a negative 0.21, so roughly 1% change. That was effective March 1st. All of Magellan's tariffs on the index side were reduced by roughly 1% on March 1st. Just that 1% is roughly $3 million annually in tariff revenue for modeling purposes. At this point, you know, there's likely to be some challenge to that change. However, our view right now is that we're planning on the -0.21 adjustment for the next five years. That rolls through 2025 at this point. The FERC index rate all in when you look at our adjustments that we're planning to make on the market base, which is roughly 5% or maybe a little bit north of that here on July 1st, 2022. The index markets right now are trending to be right around 8.7, and that's after the 0.21 adjustment. In total, it's about 6% on average across our entire system. That takes effect July 1st. Our average rate, and this slide has been perplexing to a lot of people because we're increasing by 6%. It shows a flattening. Again, we talked about this in guidance. This is really 2021 was inflated slightly because we had some specific areas of our system where there were shippers that had commitments, and they chose not to ship those barrels, and so they paid us a deficiency, so it changed that equation of the average rate. We don't expect that to repeat itself this year even though it could, but we don't expect it to. That's making part of that change. The other part of it is, when we brought on our Houston to Hearne project, part of our Texas expansion systems, we have some short haul movements of very high volumes that are at lower tariffs, driving that average down a little bit. So that's really the story behind it. Really the big point I wanted to make on this slide is, you know, the relative cost of moving barrels in our system versus other modes of transportation. You know, Aaron mentioned our average rate per gallon is $0.04. If you think about that from the current retail price, the average retail price in the U.S. right now is $4.25. That was Monday. It might have changed by $0.10 since then, but as of Monday, it was $4.25. The relative cost to move barrels hundreds of miles in our system is less than 1% of that cost. If you think about that's a pretty compelling story about how efficient our systems really are. Another important relative factor is if you look at the trucking costs between our truck racks and retail, these are typically, you know, anywhere from one to maybe 10 miles around cities in the U.S. and around our system. That's about double the cost. It's about $0.08 a gallon compared to us moving it hundreds of miles throughout our system. Some pretty important facts that really show the value of our system, not only from an economic perspective, but also from a carbon perspective. It's the most efficient mode of transportation by far, and the safest mode as well. Lastly, on this slide, Aaron mentioned a little bit earlier, but I wanna reiterate it here, and that is, you know, our operating margin for refined products is around 70%. In inflationary periods, like we're in today, yes, we're able to increase rates. If expenses increased at the same rate, we're still expanding operating margin in that scenario. However, in 2022, we're expecting, and we shared this in guidance, expense growth of about 2% this year. We're widening that margin today. That's largely due to a business optimization efforts that we undertook starting in 2019 that have started to curb some of our expenses. That's been a pretty successful endeavor at this point. I think that proves it. Storage. This isn't the rosiest of stories in the current market, but we do see some tailwinds on this here very recently. We have about 40 million barrels of storage that we use for contract storage throughout our systems for refined products. About half of that is in our pipeline system. The other half is in our two marine facilities in the Gulf Coast. There's really three main types of customers that we lease storage to. There's refiners, there's retailers and marketers, and there's traders. Typically, in a downturn market where the commodities market's backwardated, therefore it costs them money to hold barrels because they lose value on the commodity. Typically, during that period of time, we see traders start to come out of storage. The other customers, which are the majority of our storage, refiners, typically will hold onto storage because, you know, they have integrated economics. Their goal is to keep the refinery operating, so they want space to put their barrels into. On the retail side, it's the exact opposite, where they want security of supply. In a low inventory market, if barrels become short in the system, they wanna be able to store some barrels in our system to be able to supply their stores. This refined product storage business is roughly 12%-15% of refined products operating margin. As I said earlier, demand over the last 12-18 months has been challenging. There's really three factors in that, the biggest one being the backwardated market. If you're in a perpetual backwardated market, versus a carry, it just changes the entire equation for holding physical barrels in our systems. The other one is, you know, coming out of the pandemic, we saw lower demand, and we saw lower refinery utilization. We've also seen refinery rationalization that I mentioned earlier. That brings barrels out of the market, therefore, there's less need for storage. That is recovering right now. Of course, competition at our marine facilities, that's also been a big factor. This is a cyclical market. We recently did some pretty big deals in the Gulf Coast to reup about 3 million barrels, which has been pretty successful. We're starting to see some light at the end of this tunnel, in other words. If we see the market correct and commodity prices all in come down, and we get back into a carry market, we'll see this jump again. That's really the reality of that piece of our business. Right now it's impacting rates and terms on some of the deals that we're doing. Our commodities business. Really, our commodities business can be thought about in two big buckets. It's our gas liquids blending and then our fractionation business, our transmix fractionation business. It's about 70/30 between those two businesses. I'm gonna focus today almost exclusively on gas liquids 'cause that's the biggest component. Our gas liquids business can really be thought about in four different ways. The quality margin, how much physical margin is actually available in the gasoline, the financial spread between gasoline and gas liquids, mainly butane, but also natural gasoline. Then cost, the cost to get those gas liquids to the point at which we can blend them. That includes trucking, storage, and also RINs is another cost. Then the last one is risk management. How do we look at the financial risk, and how do we hedge that in our system? Starting with the quality margin, really, we have access to real-time data in our system that shows the volatility of gasoline. Volatility of gasoline based on EPA regulation comes down in the summer months, and then it goes back up in the fall, winter, and spring. That's where the majority of our opportunity in blending is in the fall, winter, and spring. That's why you see our cash flow in this business more so in the first and fourth quarters of the year. We have real-time data that shows us the volatility. We also have this access to this fungible system, where we can move barrels around behind the scenes physically and be able to capture that margin. That's a really important component. This is about. If you take the total volume of our gas liquids business, it's about 2% of our gasoline shipments all in across our system, and that's capturing a pretty big chunk of that margin. We are optimizing this business right now and looking for more margin because there is some there. It's just a matter of being able to get to the right spot to capture it before it leaves our system. The financial spread, if you look at the forward curves for gasoline, RBOB specifically on the NYMEX, and you look at the forward curve for the D0 contract, that's the butane contract in Mont Belvieu, also traded on the NYMEX. That's a good indicator of the forward price spread between gasoline and butane, but it doesn't tell the entire story. Obviously, we're hedging these volumes early on. Most of our hedging occurs in the spring and in the summer months. That's because the price of butane typically drops starting when the RVP blend down starts, and that's because refineries start dishing out butane or not consuming as much. At the same time, the summer driving season starts for gasoline, and so typically we'll see RBOB expand at that point, widening that gap. That's when we start doing our hedging. This year, in particular, it's a very unusual year. Those margins spread out pretty wide early on, so we're well on our way in 2022 with hedging for the fall of this year and for the spring of next year at pretty robust margins. Our guidance this year for this business, we said it would be roughly $0.40 a gallon net margin all in across the entire calendar year. That's going into that period of time, we were about 50% hedged, so we had all the spring hedged. We hadn't started hedging the fall. Now we're hedging the fall as we speak. Those are at pretty good margins. Something working against us, though, is the current basis differential for gasoline in the Midwest and in Texas compared to RBOB. If you follow that at all, that's a good indicator. We can hedge that at times, the basis differential, but it's not a very liquid market, and we can't get it all hedged typically, and it doesn't go very far out on the curve as well. In saying that, we are getting better margins right now in the fall than we had planned in guidance, but we're taking a hit on the current barrels we're selling in the spring because of the basis differential. I would say all in right now, we're not planning on changing guidance at this point, today, but there's a lot of moving parts as part of that business, that I wanted to make clear on. Let's see. On the charts, you can just see the history of cash flow on this business and also on the outright net margin. In addition to that, RINs, it's been a hot topic of discussion. We've seen the prices escalate here over the last year and a half, and that's really driven by the blend wall, the ethanol blend wall. During the pandemic, the EPA kept the renewable volume obligation for the U.S. expanding every year, and when demand for gasoline and diesel dropped, that blend wall started to hit. That increases the price to comply with this business and increase the price of RINs. We've done a lot of work on trying to figure out a way to hedge this cost and this risk. Ultimately, Magellan, because of our blending business, we are considered a refiner in the terms of the EPA in this business. Every gallon we produce of gasoline, we have to produce a RIN to offset that. That is a pretty significant cost. That's factored into our $0.40 net margin for the year. Lastly, I'm gonna hit on renewable fuels. I won't hit ethanol and biodiesel all that in detail. I think you pretty much probably know that story. We have the capability of blending ethanol at every single one of our truck terminals. Those barrels are typically trucked or railed into our facility. They're stored in our facility, and we blend them at the truck rack before the gasoline leaves our system. On average, we're blending about 10% of our gasoline with ethanol, and that's driven almost solely by the Renewable Fuel Standard. We have that capability to go all the way up to E85 or down to E0. We have ultimate flexibility in this business. If you look at the fees we get on storage and on injection fees for ethanol, it's about on par with our average tariff. We're really indifferent whether it's blending ethanol or moving a barrel on our system. We're almost indifferent from an economic perspective. Biodiesel is a little bit different story. You know, the renewable fuel standard has driven the demand for biodiesel to some extent, but it costs a lot to produce biodiesel. The economics haven't always been there for biodiesel to compete with the price of diesel fuel. In fact, today, with the growth in renewable diesel and SAF, sustainable aviation fuel, they're using a lot of the same feedstocks as they use for biodiesel. All those prices for feedstocks are driving up right now, driving that cost up. Biodiesel hasn't taken off in the same way ethanol has. Ethanol is a more efficient product to produce, frankly. In the biodiesel, even with a $1 tax credit and with the RIN value, still at times is very uneconomical to blend. At the same time, we have states like the state of Minnesota, who has mandated the use of biodiesel. We have injection capabilities throughout that entire system. We blend it, B5 in the winter and B20 in the summer months in the state of Minnesota. We have that capability. We talked about a couple other projects in Missouri that we're doing right now, where we have got some incentives. By and large, you know, we're moving on that piece of the business, but only when it makes economic sense. When the underlying price of the renewable fuel doesn't always compete with the base diesel fuel, it makes it tough to make investments. Our customers see the same exact thing. We're always weighing that. Ultimately, what will drive the biggest growth in biodiesel is if more states mandate it. That's probably the only way this happens in the near term. On renewable diesel and sustainable aviation fuel, we've done a ton of research on these products. Unlike biodiesel and ethanol, they're purely drop-in fuels, meaning the specifications for renewable diesel exactly meet the specifications for diesel fuel. So you can run 100% renewable diesel in a vehicle and be just fine. I think that is a huge differentiator between biodiesel and renewable diesel. The challenge is the cost again. To really scale these products, the industry is gonna have to figure out supply of the feedstocks. Today, that's by far the biggest challenge. The other challenge, as Aaron mentioned, is the regulatory environment. There's really only two areas where renewable diesel and sustainable aviation fuel make any economic sense, and that's if it's consumed in the state of California or consumed in Europe. That's where most of it's going today that's produced in the U.S., almost all of it being transported by rail, truck or ship or barge today. Very inefficient. We are well positioned. Magellan is very well positioned to handle these products. Again, it's gonna take time for this to evolve, both on the regulatory side and on the supply side of this piece of the industry. We're already connected to major airports around our system, including Houston Hobby, Houston Intercontinental, Dallas Love Field, Denver International, Kansas City, Minneapolis. You name it, we're connected to those major airports. We already have the connections, assuming the demand is there long term. On the renewable diesel side, we're connected to major railroad fueling depots across our system, of course, all of our truck racks, and then other offline areas around our system. Although these aren't we don't have a lot of big projects here to share with you today, we are well-positioned, and we've done the research to take advantage of this. The other thing is we've been very engaged in the market, talking to suppliers, talking to the producers of feedstocks. Some of our Gulf Coast facilities, for example, are very well positioned to handle feedstocks. We think long term, if these products are gonna be sustainable in the U.S. and be at scale, there are gonna have to be imports of feedstocks. There's just not enough land capacity in the U.S. to produce the soybeans, for example, to create soybean oil. We think there's gonna be demand for that longer term, and we're well positioned to do that. We're having a lot of detailed discussions around that kind of stuff today. We're talking to customers about potentially renewable diesel production, you know, actually building facilities. The refiners have a head start on this because it does take hydrotreating to produce renewable diesel versus a biodiesel that doesn't need hydrotreating. There's some advantages that refiners have today, but there's some possibilities if this grows at scale that we're gonna have in our system. The other thing we have in our system is this open stock I was talking about earlier. If someone had asked the question, you know, what would we like to see out of the regulatory environment? If there is a low carbon fuel standard, in our view, it should be where it doesn't matter where that product is actually burned, okay? If this is truly about climate change, then it doesn't matter where the product's burned, if it's renewable diesel or SAF. Therefore, we should be able to fungibly put it in our system at some percentage and ship it around our system, and customers can move the paper wherever they want, just like our system operates today. That is by far the most efficient way to go about this, but we'll see how the regulators handle that. With that, critical assets. We've talked about that, and about how our system operates and why those are critical to us and our customers and to the marketplace. We've talked about the macro market dynamics and how that's producing opportunities for us right now, and we see more of those coming down the pipe. Largest components we talked about were transportation, we talked about the pricing structure, storage, and then commodities and also renewable fuels. Then the last thing I'd like to say is that we're gonna remain disciplined on our capital outlay. You know, these opportunities that come up, we are gonna take advantage of those when it makes economic sense. If we don't feel good about the long-term underlying market or the commitments on those projects, we're not gonna do them, and we'll return our capital back to the investors. With that, I will open it up for questions. Yes, sir. Hey, Mark. Spiro Dounis from Credit Suisse. Wanted to ask about the elasticity as it relates to demand. You mentioned before about gasoline obviously getting pretty high these days. Not really seeing the impact, though. It sounds like based on. Mark, sounds like the system's pretty well set to endure that for now. Curious why you think that is. Maybe more broadly, how you think about the price of gasoline demand impact, you know, what price starts that change? Right. Yeah, that's a good question, and we've done a lot of work on this front, obviously. If you look at the average price of gasoline throughout the U.S., as I quoted earlier, it's about $4.25. If you look at the West Coast, it's almost $6 at retail. Our market areas, I actually just pulled this up yesterday. In Tulsa, Oklahoma, for example, it's $3.80 right now. In the state of Minnesota, it's $3.90. The state of Colorado, it's just under $4. State of Texas, it's about $3.90. So far, and you know, we've seen prices escalate like this in the past, you know, with inflation. I would think that when it starts getting, you know, mid $4s up to maybe $5 a gallon, that could start having some demand impacts. At this point in 2022, and looking at just March specifically, our growth is right on track. At this point, we just do not see significant impact on demand overall with not related to price, at least. Hey, Mark. Thank you. Michael Lapides from Goldman. It was interesting in the last couple of days to see a number of your peers as part of a consortium filed, I think in the Fifth Circuit, maybe in the D.C. Circuit, to challenge. I would think it'd be the D.C. Circuit, to challenge the ruling by the FERC revising the five-year tariff review and reset. Can you just talk a little bit about that and a little bit about your views on whether there's, or the company's views on whether there's something structurally wrong with the FERC, the changes the FERC made? Yeah. Very good question. I want to actually hand this off to Mike. I do have an answer for you, by the way. However, Mike. Yeah. Mike is much more suited to answer this question. Yeah. The short answer there is, the designated carriers did file in the Fifth Circuit. That was intentional. They're coordinating with AOPL. We just felt that the Fifth Circuit was probably gonna be a more friendly venue, and it's gonna be a venue of first impression that doesn't have the history that the D.C. Circuit does, with regards to these issues. In particular, the two items that are open for challenge are how the commission treated the income tax issue and the data set. I think the issue of the income tax treatment is a more compelling argument, and I don't think the parties have actually decided yet if they're gonna appeal both of those items or just the tax issue. AOPL did file an appeal also in the D.C. Circuit that was now consolidated in the Fifth Circuit. All of that was intentional so that it could all wind up in the Fifth Circuit. You know, I think we've got a compelling argument on the income tax issue, and if we win on that, it won't obviously go all the way back to PPI + 0.78. It'll be somewhere in the middle. We'll have to see how it plays out. Unfortunately, as you know, it won't be quick, but we do think we've got a compelling argument there. Thanks. Hi. Keith Stanley from Wolfe Research. I had two questions. First one, just you mentioned 2022, where you had the shorter haul movements and loss of deficiency revenues that kind of offset your tariff increases. Is there any risk of items like that happening again over the next few years and offsetting some of the tariff tailwinds, or is that more of a one-time item as you see it? There's always that chance. You know, about half of our tariff volumes on our system are tied to some kind of contract, whether it be market-based, take or pay, or other structures of contracts. On those take or pay contracts, there's times when it makes sense for a shipper to, you know, not ship into a certain market for a period of time and just pay the deficiency. That doesn't happen very often. I think this was somewhat of an anomaly. We don't see it, you know, repeating in that magnitude that we saw. This was a particular area of our system that with a particular customer that had a very specific issue that they were dealing with. It wasn't market-driven, really. All in, I would say that repeating itself probably isn't going to happen. Now, the short haul, that moves around in our system. You know, dynamics happen. Like, go back to 2021 when the winter storms came through in February. We saw refineries shut down. We saw Magellan assets shut down, and then we were able to start our assets almost immediately when that passed. Oil refineries took weeks to start back up. During that period of time, we had huge advantages because we were shipping barrels long haul into those markets to meet the demand. Really, it was critical for the areas that we operate in that we were able to do that. That's an example of an anomaly that sometimes happens that creates those longer and shorter haul type movements. The one that I'm talking about in particular right now that's impacting this year is part of our HoustonLink expansion that we did where it's a unique structure where we're getting a lot of volume at much lower rates, you know, down in that $0.30-$0.40 per barrel rate, which is driving our overall average down. Thanks. A different question. In the presentation, it seems like you had some interest in seeing good demand in West Texas and even further west into Arizona, and Mexico. Can you just give an update on how the company's thinking about a potential Longhorn conversion and what demand looks like if you were to do something like that to the west relative to kind of capacity of the pipeline, I suppose? On Longhorn, you know, we're evaluating many different types of opportunities, including keeping it in crude oil. That is one option. Refined products is another option. There's various other options. There's a lot of things that have to take place to convert that pipeline to refined products. Definitely moving more barrels west would be a key to that. We're connected to a third-party pipeline, Kinder Morgan system in El Paso that goes to Arizona. It would require more volumes moving that way, therefore less volume shipping from California over to Arizona, right? That market would have to adjust. Ultimately, the Gulf Coast refiners would have to compete directly head to head with the California refiners, which we think is possible. Kinder Morgan would have to likely expand their system to make that happen at scale. You know, these are larger type volumes, not the 15 a day I quoted on our expansion we're working on right now. In addition to that, likely more volumes flowing into Mexico, northern Mexico. We have that pipeline capacity to do so. That's another possibility. There's also this whole regulatory piece of converting Longhorn that will likely take a couple of years to get done if we go down that path. We're actively working on multiple scenarios with Longhorn. We're not prepared today to talk about what path we're gonna go down. I'd say right now it's gonna stay in crude oil at the moment. We're working down the path of finding the ultimate best opportunity for us and the investment community in Magellan for that asset. Could be refined products, it could be something else. We're doing those in parallel. I would say later this year, we'll have a much better picture on that. Hey, Mark. Michael Cusimano, Pickering Energy Partners. Can you review the philosophy around hedging the blending business? I realize you don't have a crystal ball today, but I believe there's some margin that you'll hedge away that you could be making today. Yeah, if you can just talk about if we continue the backwardated market, if that framework could shift or does RIN volatility even allow you to go unhedged? Yeah. Yeah, that's an interesting question, and something we debate all the time. You know, we've chosen, really since the inception of this business, not to take a lot of commodity risk. If you look back, we've done the analysis looking back on our hedging program and compared the value we lost versus gained, and it's not even close. We've gained a lot more historically than we've lost on our hedges. There's times when we've taken some risk. For example, you know, in 2020 when the pandemic hit, everything dropped. We went a little bit long on butane for a period of time. You know, we do stuff like that. We move our hedges around throughout the year to try to capture the most margin. At this point, you know, our philosophy has been this is a relatively small piece of our business. You know, around 15% of our cash flow or our operating margin comes off of this gas liquids business. We don't wanna take a lot of risk on it. The margin is there. We go capture it if we feel like it's fair and we feel like we're not taking a ton of risk. We do take risk on parts of it. We don't hedge everything, and so we leave some exposed, but those are pretty small quantities. I'd say our overall philosophy, though, is let's—when the margin's there, we know we can capture it, let's take it off, let's take it off the, you know, off that risk. We've been pretty successful in doing that. You know, hindsight's always 20/20 in the trading business. Our view, though, is if we can capture margin that we're happy with. Also, we set our point of view on all these commodities. We're not just arbitrarily picking the point in time. We're doing a lot of research behind the scenes, looking at the future price of butane, looking at exports of butane, what does that do to the structural price? We're looking at, you know, where volumes are in the market. Are they in Conway? Are they in Mont Belvieu? Of course, gasoline is seasonal, but we're looking at that structure as well. We're evaluating this pretty extensively throughout the entire year. Before we ever get into the hedging season, we have a pretty well set plan that we're gonna do based on our point of view. Now, you get into it and you see opportunities, that's when you go capture them. That's the moment we're in right now, where we're seeing margins, you know, better than what we expected, and we're going to lock those in right now. I understand the question. You know, this has been a debate for years at our company. Ultimately, we wanna guarantee cash flow. That does it when you hedge those volumes. You're guaranteeing that cash flow. Mark, we have two more questions, and then we'll move on to crude. Okay. Hi. Neel Mitra from Bank of America. Just lay out two questions. One, you've laid out kind of the refinery shutdown, the short haul projects. Longer term, you know, just directionally, do you see longer haul projects? And regionally, where could they come from? And then, second, to kind of piggyback off of Keith's question, if you were to do a Longhorn conversion, how would that impact kind of the downstream terminaling business on the Gulf Coast with the crude business? Yeah. On your first question, I think I got what you asked, but let me try to answer that. You know, we are seeing some areas of our system where we are getting longer haul type movements. You know, I mentioned the Colorado piece. Those are pretty extensive tariffs that we achieve into that market. Our Texas tariffs are some of the best in our system, moving out to West Texas into El Paso. Again, those are growth areas. Ultimately, the markets are gonna drive that. And that whole supply-demand curve that I talked about, that's gonna drive those opportunities. As far as refinery rationalization and what's going to happen going forward, it's hard to tell. We think there's gonna be more growth in renewable diesel and SAF, which is gonna drive some refineries to convert or at least part of their refinery. We think we see that happening. Those should create opportunities for us if they're anywhere around our system, just like they have in the past. You know, if demand does what we think it's gonna do over the next few years, I struggle to see more refineries shutting down at this point. If they do, they'll be very unique spots around the U.S. that you know, are struggling economically today in those markets. Crack spreads are strong right now. For the foreseeable future, I struggle to see that happening in a big way. I don't know if that answers that first question or not. It does. Thanks. Okay. Your second question was, again? Just with the Longhorn conversion, how that would impact kind of the downstream business in the Gulf Coast if you were to do that with crude oil. Well- Crude oil. Yeah. On the, I'll probably let Robb answer that question on the crude oil piece, on how it impacts the downstream markets. I think the short answer is, if we do something different with Longhorn, we're gonna have to displace the crude barrels. We have long-term commitments on Longhorn, and those are gonna have to be put on another pipeline system at some point if we decide to do that. We're gonna be strategic on how we do that. You know, we own a portion of BridgeTex, so that would be an option. If we do that, those barrels will flow into our system just like they would if they were otherwise on Longhorn. That's the short answer. I'm gonna let Robb hit that in more detail if I didn't answer it appropriately. One more. Hi. Theresa Chen, Barclays. Just real quick to clarify your comments on the butane blending piece. As you sit here today looking to the fall of 2022 and spring of 2023, granted the spot margins are wider than originally when guidance was given, but the basis has moved against you. Is one factor winning over the other at this point, or is it pretty even? It's pretty even right now. I would say we might see some. We're not all the way hedged yet in the fall. We're a portion of the way through that. Depending on what happens here on the forward curves over the next month or so or two months will help dictate that. Right now, I'd say we're marginally ahead on the fall versus the current spot basis differential. At this point, I wouldn't. You know, we're not prepared to change guidance at this point. I think they're pretty much offsetting each other at this point with what we've hedged and what we're seeing on the basis. With that, I just wanna thank everyone and appreciate your interest in Magellan. Robb Barnes will be coming up here. Robb has commercial responsibility for our crude oil business. I'm walking slowly. We're working through a technical issue on the monitor here. Yeah, you don't want me to wing it or we'll be here for an hour and a half, and who knows what we'll be talking about. All right. I think we're there. Oh. That was my job to turn the page here. I'm just gonna take the next 15 or 20 minutes and talk about our crude oil business, provide some highlights on the crude space. There's some metrics at the top of this page. I'm not going to go through all of that. I will highlight the 29 million barrels of contract storage, which is storage that we have available to be leased out, and I'm gonna talk a little bit about that on a future slide. I just wanted to kinda highlight that number. If you look at the map, a couple things I wanna point out are, as you can see, the majority of our crude oil assets are located in very strong energy states of Texas, state of Oklahoma. We believe that that provides long-term stability around our crude oil assets. Just to highlight real quick, our Saddlehorn pipeline comes down from the Colorado area, gathers barrels in the DJ Basin, the Powder River Basin, and pulls those barrels, funnels them down into Cushing. We have a significant terminal presence in Cushing. In Cushing in general, if a barrel is in there, the owner of that barrel then has various options to try to maximize the margin that they receive on that barrel. Getting that barrel to Cushing, which is what Saddlehorn does, is a big part of why that pipeline is successful. Looking down in Texas, our Longhorn and BridgeTex pipelines. Longhorn's on the bottom, originates in Crane. Those pipelines funnel barrels into the Houston market, which then move down our Houston distribution system and can also get into our Seabrook terminal for export across the water, and I'll talk about that a little bit more on a future slide. The Permian crude oil pipelines, this chart should not be a surprise to anyone. It clearly shows that the Permian Basin is in an overcapacity situation on excess pipeline space. When you look at the projected projections around production, depending on what your viewpoint is, the Permian Basin and the increase in production filling up space is a positive note on a long-term basis for both of our pipelines, our Longhorn pipeline and our BridgeTex pipeline. Kind of going back a little bit, Magellan was one of the first companies that looked at constructing a pipeline from the Permian Basin down to Houston. We were pretty far along in that process, and we quickly realized at that point that there were several pipelines looking to be constructed out of the basin. We pivoted fairly quickly and said we did not want to participate in one of the pipelines going down to Corpus for the reason that in the situation a lot of those pipelines are in today. What we did though was go back to our existing pipelines, BridgeTex and Longhorn, and say we believe it's in Magellan's best interest to contract those pipelines up on a long-term basis. When you look at Longhorn, 75% of the space available on that pipeline is committed with a weighted average remaining life of 6 years. The current expected tariff for 2022 on Longhorn is roughly $1.50. On BridgeTex, 70% of the available space is committed with a weighted average remaining life of 4 years. The expected tariff in 2022 on BridgeTex is roughly $2.50. We anticipated the environment that we're in today. We locked up capacity on our Longhorn and BridgeTex pipelines for the most part. We're constantly talking to producers, traders, refiners every single day on trying to talk to them about additional long-term commitments on our various pipelines. Short-term commitments, we anticipate in 2022 on Longhorn moving roughly 240,000 barrels a day. We have some short-term contracts in there in addition to these long-term committed contracts, filling the space up, moving them down into the Houston market. Just kind of taking that step a little bit further of if you're a producer or an owner of a barrel sitting in the Permian Basin, they obviously have choices on what they wanna do with their barrel. We believe that best choice is taking it to the Houston market, and that's driven by some facts, and we just wanted to highlight a little bit of that here. If you look at the refining capacity in Corpus Christi versus Houston has roughly 3x the amount of refining capacity as Corpus Christi does. On top of that, for the most part, Corpus Christi did not have long-haul pipelines feeding those refiners. Those refiners, over the past 20, 30 years, have been self-reliant on making sure that they have crude to feed their refineries. They did that themselves. Now they have these long-haul pipelines. They don't necessarily need the long-haul pipelines to supply their crude into their refineries. A barrel going to Corpus is generally looking to go across the water. When you look at Houston, we have the capability to take barrels across the water, not to the size that Corpus does, but you know, the U.S. is exporting roughly 3 million barrels a day of crude today. Houston has roughly 2 million barrels of that export capacity. You can't satisfy all of it, but you can satisfy a majority of it if that barrel just wants to go across the water. What we believe is the key for a producer or an owner of a barrel in the Permian Basin on where do they wanna take their barrel is the optionality and flexibility that Houston provides. I think that is the key word here is optionality and flexibility because a barrel that someone puts into a pipeline when it's leaving the Permian Basin, it takes some time to get to the end destination, whether that's Corpus or Houston. Ballparking it 10 days, and then what do they wanna do with that barrel? In our ever-changing world, you know, every single day, new decisions need to be made on the best margin and the best possibility to extract the highest margin on that crude barrel. Going to Houston, they can sell it into the HOU futures contract that we've established with Enterprise. They can move it to one of the 2.6 million barrels of refining capacity and eat that barrel up that way. They can move it to the water. There's a lot of variables and a lot of flexibility that the Houston market provides over the Corpus market, which is why we believe it's a conversation we have with a lot of those producers out there. They like that optionality. If you talk to a trader, having the ability to make day-to-day decisions with your barrel is a key to what they wanna do with their production. Enhancing our Permian value chain. Said differently or said more simply is what improvements are we making in our pipeline system to provide a better midstream option for our customers? These are some of those highlights. The first one, which really covers kind of the origin side of our pipeline business, we're always looking to diversify, add new supply sources, provide the ability to take a barrel into our terminal at Crane, for example. If a customer wants to move it to either the Epic pipeline or the Gray Oak pipeline, we have new connections that allow them to do that. They get into our system. They can move it to Longhorn, but they can sell and buy a different barrel. Providing a lot of flexibility on the origin side, we think attracts a lot of volume and a lot of business to our pipeline system. The next two points are on the pipeline side. In today's environment, we think it's very important, and after talking to a lot of our customers, to take potential risk out of the game. Simplifying our pricing, which allows a customer to know what their actual cost is to put a barrel into the pipeline system, get it to the Houston market. They then can trade it into the HOU contract, like I talked about. They know upfront, before they ever put that barrel into the system, what their cost is going to be to move it across the water or to sell it into one of the refineries. They don't have to rely on a third party, which is something Aaron touched on in his discussion. They don't have to go and rely on a third party to move that barrel to its final destination. It's simple. You don't get layering of tariffs. You don't get layering of PLAs, which in today's environment, with crude over $100, your PLA is a significant factor in the decision on where to place your barrel as a producer or as a trader. Looking at the last two bullets, these are more on the destination side. In our Seabrook facility, you know, it's historically and always has been a WTI terminal that moves WTI out to the water. We're in the process now of adding additional grades. We're looking at adding a heavy grade across the docks and light grades. WTL can be moved across the dock. Providing flexibility and meeting the needs of our customers to attract barrels into our system. Our HOU joint futures contract, which is another option that our customers have if they put a barrel into our system to maximize the value of that barrel. I'll touch on the HOU contract here in a few minutes. Well, right here. The HOU futures contract structure improves liquidity, price transparency for the industry. What it really does is it allows a barrel in Houston to be priced at the Gulf Coast versus having to hedge that barrel against Cushing. What that does is that reduces pricing risk for anyone who's hedging a barrel against that Cushing WTI barrel. The reason for that is if your barrel's sitting on the Gulf Coast, and you're hedging it against a Cushing WTI contract, there's still that location differential. What that means is you've hedged it against Cushing, but your barrel's in Houston. The WTI pricing is in Cushing. There's still a value difference between those two locations. What then customers have to do is they have to go and buy additional contracts to offset that location difference or that basis risk, and that costs money. We didn't go and establish our HOU contract on our own. We established our initial HOU contract based on the industry coming to us and asking us to help provide a solution for the problem that's existed for a long time. We did that. If you look at the very bottom, the chart on the left, we established our HOU contract a few years ago. Enterprise established a futures contract on their own at their terminal in Houston at the same time. Neither one of us could capture the liquidity necessary for a customer to hedge their barrel against one of those futures contracts and know that they're getting an accurate and fair price, 'cause that's the key to that is liquidity. You can see on the far left there, while we had our HOU contract, this just shows 2021 volume here, but our volume was very low. We did not have a significant amount of liquidity. Therefore, there wasn't a lot of deals being done against it. Starting in January, during this time period, we were working with Enterprise and ICE. We established a joint HOU contract, so we took our existing HOU contract, worked with Enterprise and ICE. Enterprise canceled their futures contract in the Houston market. What we did is we've created a joint HOU WTI futures contract that allows our facility to be used, our East Houston terminal, as it always has. We brought in Enterprise's Echo facility, increased the capability to provide increased liquidity. We've allowed free flow of barrels to go back and forth between those facilities, which the market said that they were looking for and was one of the necessary components for them to utilize the HOU contract down on the Gulf Coast. As you can see, we kicked it off here in January with March as the first delivery month under that contract. In the first couple of months here, you know, there's been 31 million barrels traded in that HOU contract. The liquidity is increasing. Our customers are becoming more familiar with it. This isn't one of those things that you can say in two or three months from now, it's going to be a success. It's going to take time to build up that liquidity, build up trust amongst the traders, but there's positive momentum that this is going to supply and be that new solution for taking away that location risk or that basis differential risk that customers have to. It's gonna be at a lower cost. A lot of positive momentum on the HOU futures contract. Our Houston distribution system. You know, if you've attended one of these in the past, we have put this slide up here, and this is a simplified look at our distribution system in the Houston market. We think this is one of the benefits of putting a barrel in one of our long-haul pipelines. As you can see at the very top, Longhorn and BridgeTex come into our East Houston facility. I'd like to point out, this is a simplified look at our distribution system. There are multiple pipelines in many of these corridors. Going from East Houston down to Speed Junction, there's three 24-inch pipelines or two 24-inch pipelines or 20-inch pipelines. This just looks like one, but it's a simplified version of that. There's so much flexibility built into this distribution system, that you can take a barrel, as I touched on earlier, and you have a lot of options on where you want that barrel to go. We're connected to all the refineries, directly connected to all the refineries in Houston, indirectly connected to a majority of the refineries in Louisiana. Depending on where the highest margin for that barrel is, our customers have the option to do all of that and take that barrel to that final destination. I'd also like to point out a couple of new enhancements in the distribution system. The Wink to Webster pipeline that recently started up. It's down at the bottom there. ExxonMobil's Wink to Webster at the very bottom of the diagram there. We have made a connection into their Webster facility, which is the destination point for that pipeline. There are two pipelines, both that feed into our system. We have a 24-inch pipeline and a 26-inch pipeline down there where that connects in. We can take those barrels south to Texas City, or we can take them north up into the distribution system and be that final leg for movement for the Wink to Webster pipeline. We can do that at their full rate. We can receive at 20,000-25,000 barrels an hour. When you do the math, I mean, we could receive essentially 1 million barrels a day coming off of Wink to Webster, which is the capacity of that pipeline, taking away the portion that goes to Enterprise. We have a significant connection available there for them. Looking at the very top of the map, you can see our East Houston facility and the Houston Link pipeline that comes in. That's fed from the Marketlink pipeline that comes from Cushing. That pipeline can feed barrels into the system, heavy barrels, a lot of different grades coming in that various customers like to utilize to take to the end destination. Then this system, we also have negotiated and capable of if a VLCC dock gets built in the Houston market, and Enterprise is SPOT dock they're talking about, then there's the TGL dock that Sentinel is working on. Either one of those, we will have the capability to make deliveries into those VLCC docks, to again, to provide the maximum flexibility for our customers. Our Corpus Christi condensate splitter, and I'll just kind of touch on. We have a fairly significantly large terminal in Corpus that not only houses our splitter, but we deal with a majority of the refineries down there, and we handle a lot of the feedstock that comes in and the offtake from those refineries for final destination or final delivery of the offtake from those refineries. That's kind of our terminal, and we have a lot of flexibility. We do a lot of bunkering for some of the refineries down there. Our splitter itself is 50,000 barrels a day. Our operations team has done a great job of managing the splitter and learning how to maximize the margin to maximize the product grades that are coming off of that. Depending if it's a middle barrel, say, jet fuel or diesel fuel, our operations team can extract a larger volume of that such that the customer gets a higher margin on those barrels. We are in the process now. We're kind of in that final year of the initial term with our existing throughputing customer, and that comes up in middle of 2023. We're engaged in conversations with them about their desire to stay in the splitter. On top of that, we have been reached out to by several customers. We've reached out to several other customers, and there's a lot of conversation going on with third parties that are very interested in stepping into the shoes of the existing third-party throughputter if they decide they do not want to stay. In addition to that, Magellan, we have done a lot of analysis on potentially being the throughputter through the facility through that splitter ourselves, where we would be obtaining crude oil, running it through the splitter, and then taking the offtake and selling it ourselves, which is something that we believe is very positive and is something that we are taking very seriously. A lot of options on the splitter, depending on how the existing throughputing customer reacts and what they want to do in mid 2023 on their term extension. I will tell you that they have a unilateral option to extend that, and the rate to do that is at a slightly lower tariff rate than what the current tariff rate is. Rockies production versus pipeline capacity. The story's very similar to the Permian. There's excess pipeline capacity out of the Rockies Basin. You can just see here production's a little flatter than it is projected to be in the Permian Basin. As an owner in Saddlehorn, we own 30%. Plains owns 30%. You have Chevron and Oxy. Oxy, Western Midstream, which is controlled by Oxy, are the other owners. They each own 20%. We feel good about the long-term support of Saddlehorn because both Chevron and Oxy are two of the larger producers in the basin up there. With their equity ownership in Saddlehorn, their long-term support, we believe is there and they're excited to continue to use the Saddlehorn pipeline to get their barrels down into the Cushing market. Saddlehorn is 80% committed with a weighted average remaining life of five years. The average tariff expected in 2022 is roughly $1.80. I finished on time. I will open it up for questions. Hi, Robb. Just going back to the condensate splitter asset. The agreement that may be extended at a lower rate, can you just quantify what kind of impact to EBITDA or DCF that would be if that was realized? I didn't quite hear the end of that. On the splitter. Yeah. If the customer unilaterally decides to extend at that lower rate, what impact to EBITDA or DCF would that be? Well, you know, it would be under the same structure, the same terms where they would be throughputting through the facility. They would take the offtake, and they would pay us a throughput fee. That throughput fee is slightly lower than what the current rate is today. I don't think that impact is. I mean, there'll be a slight reduction in the revenue we generate on that. Qualifying it from a Magellan perspective, it's not significant. Great. Yeah, there we go. Hey, thank you. Michael Lapides from Goldman Sachs. Can you talk about on the crude storage side, how are shippers signing up in terms of contract tenor, meaning contract length? And what's just happening in kinda broadly speaking, the fee rate for storage for crude right now, relative to maybe what you saw a year or two, three years ago? Yeah. Yeah, absolutely. In an effort to kind of go a little quick, I didn't quite talk about our storage program kind of in the distribution system map. We have a significant storage presence in Houston, obviously at our MEH facility, that East Houston facility. We also have storage at our Galena Park facility, which is also a refined products terminal. We have storage at our Seabrook facility that we use to export barrels, but we can also use it as a holding spot, and we have the ability to move those barrels back into the distribution system. From an overall perspective, you know, storage rates are driven by several factors. First one of those being the forward price curve. The steep backwardation that exists today essentially says that a barrel in the system today is worth more than a barrel in the system tomorrow. There is no incentive for anyone to lease storage and hold that barrel unless they have to. That's not a driver for someone to take a lease storage position in our system today. Refinery utilization is also a driver for storage, where they can stage barrels to feed the refinery. Refinery optimization is high, and so the refineries are utilizing a lot of volume. While that's somewhat of a driver for someone to lease storage to feed the refineries, not a big change to the market right now. Kind of the last one, which is where things probably are leading, is the demand for domestic and international barrels, putting barrels on the water, essentially. Demand for storage right now is not high. The price for storage is relatively low. We have available storage that is unleased, which allows us to potentially utilize that on the operations side. We have the ability to flex our storage. That 29 million barrels of storage that I touched on a little bit, we can flex that up or down depending on the market. The rates on storage are fairly low right now without a strong demand for people to lease storage. Hi. Neel Mitra from Bank of America. Just wanted to get your perspective on contracting Longhorn at this time. I know you added some contracts earlier this year. With the differential between Midland and MEH so narrow, why would you contract right now versus kind of waiting for the spot market to widen out maybe in two years with the way Permian oil production is kind of exceeding expectations? Yeah. We are engaged with several customers. Some of them take the viewpoint that they would like, and they believe that their best option is to do short-term contracts over the next one to two years. There are other customers that we believe. Well, I will say it. I anticipate that we will lock up some contracts on a longer term basis, longer term meaning year plus, at what we believe right now are premium rates because they're taking the position, and we're taking the position that kind of a term deal provides us some assurance. It provides them assurance that they can take the barrel and get it to Houston no matter what the scenario shows on the production side. If production increases, they're taking the position that they're gonna have some space locked up at a rate, and then they can take advantage of that depending on what happens with production. I would anticipate that we do end up having some contracts here in the next, you know, year or so on a term basis that add to the committed volume on that 75% on Longhorn. As well as BridgeTex. I think BridgeTex is in a situation very similar where we plan on and we anticipate having some longer term contracts locked up. James Carreker, U.S. Capital. I was asked earlier in the refined products section, but I would like to hear your take on a potential Longhorn reversal, what you do with existing contracts, how that affects your distribution system, your export facility, and I guess your overall take on what that would do to the crude side. You bet. And Mark answered it accurately in the sense that, you know, it's a two-pronged economic decision, right? First, does refined products or NGLs or whatever product we're looking to put into the Longhorn pipeline, how do those economics look and work on a long-term basis? Placing the crude. You know, we have a lot of committed volume on Longhorn. Where do we take those barrels, and how do we continue to receive the revenue stream that is generated from those contracts? Obviously, a likely choice is BridgeTex. If we can take those barrels and reach an agreement to keep that volume moving to Houston on the BridgeTex pipeline, we receive some of that benefit back. I can tell you we're also in contract discussions around moving and placing those crude barrels on other third-party pipes going to the Houston market. At the end of the day, while there's a potential we anticipate those barrels going to the Houston market, that's contractually what our obligation was on Longhorn. From an HDS and a movement around the system there, we don't anticipate a lot of impact. It's really coming down to reaching an agreement on a third-party pipeline, and our preference would be BridgeTex. Gabe Moreen, Mizuho. Robb, I think for a while there was a talk of Magellan maybe looking to get a little more integrated and going upstream from the gathering side to try to bring more barrels to your long-haul pipes. Some of your competitors, I think, have elected to do that, so I'm curious whether or not it's something you're still looking at potentially. For some competitors that have gone out there and bought some gathering systems, do you think it's making any difference for them in terms of filling up their long-haul pipes at this point? You bet. We continue to look at that. You know, I look back at what we've done over the last 10 years, and I'll be honest, I'm glad we did not pull the trigger on acquiring some of those gathering systems just with the competition out there. Our emphasis has shifted a little bit in that when we're having conversations with gathering systems, they're also looking at providing security for their barrels to get to an end destination. It circles back into that concept of if a producer at not only at Crane or at Colorado City, the origin of our Longhorn pipes, but if a producer has the ability at the origin point of a gathering system to have a single price and a known price all the way down to Houston or to the water, that's a good thing for them. We're working with some gathering pipeline systems to provide that, where they went out, and they can attract a lot more volume to their gathering system, but we can also pull it into our long-haul pipe. It's a win-win for both of us, and that's kind of the context that we're moving under versus acquisition of a gathering system. I think that's it. Jeff Holman, CFO, is coming up and providing his insights. Okay. Thanks, Robb. I'm Jeff Holman, the CFO, as Robb said. I realize we've all been sitting here for a while. I'm acutely aware I'm the only thing between us and lunch. One of the things we're gonna miss about having a CEO with a lot of experience, one of the things that allows you to do is predict very accurately how long these presentations are gonna take. Mike was very sure this was gonna take longer than all the rest of us. I personally was very confident we were gonna be well within time, my section particularly. We've got a lot of ground to make up. I'm gonna move as quickly as I possibly can, but I'll try and do that without losing you. What I'm gonna try and do today is just build on everything we've heard so far today and tell you what we think it all means for Magellan, particularly from a capital allocation standpoint. Definitely, one of the lines of questions and comments we've got the most over the last couple of years from investors and analysts has been around capital allocation, so we wanna make sure we talk about that today. Now, it's a Magellan presentation, so there's not gonna be a big reveal. Maybe I think you would sort of be alarmed if you came here and you heard something you'd never heard before, so don't worry. It's gonna be all stuff that we think you'll be very familiar with, but we just wanna be as careful as we can to communicate exactly how we're thinking about things and give you a chance to ask questions about that. I'm gonna spend most of my time on capital allocation. Also, the capital discipline that informs that approach on capital allocation. I wanna talk briefly about the total return proposition we think Magellan offers and touch on our distribution on that as well. Okay. There's a lot of words on this slide, but what we're trying to communicate here is actually really pretty simple. What we've just shown is on the left side is just sort of the current landscape, the things, the features of the current landscape that we think are most important in informing our capital allocation decision, where that leads us, or the conclusion that leads us to from a capital allocation standpoint. On the right side are just a few things that we think. There's some considerations, some things that could rise, that could cause us to revisit that conclusion. Again, it's all things that you've heard already today. The first of those is just that our core business is very, very stable. You've heard that throughout the day, right? We have a very resilient business. Aaron talked about how our assets are gonna be needed for decades to come. Mark showed you that refined products demand chart that was so steady over the last 20 years. Robb talked about our crude oil pipelines, how well contracted those are, and how that space is improving. The point of that is just that our core business is very strong and is generating a lot of cash. Second, as Mike started off today, you know, we've long had a commitment to a strong balance sheet. Where we sit today, we feel like that balance sheet is in good shape. We don't think we need to allocate additional capital in making it stronger, so we don't feel like that's a strong draw on our capital allocation at this moment. You've also heard us acknowledge this morning, but also pretty consistently, I think, over the last few years, we think we're in a low capital environment, and we're probably gonna be in that, in that kind of environment for a little ways to come. Refined products is a very stable business. We talked about some growth opportunities there, but it's clearly a very mature business. It's essential infrastructure, but not offering a lot of investment opportunities just at the moment. The crude oil space remains pretty competitive and somewhat oversupplied currently from an infrastructure standpoint. Finally, as Aaron talked about from an energy transition standpoint, we don't see a lot of investable opportunities at this moment, and we really don't know when that's gonna change. All that leads us to conclude that our focus on capital allocation is gonna be on returning capital to investors, that that's gonna be the best way we have of delivering long-term value to our unitholders at this time. Of course, that isn't a one-and-done kind of analysis. We're gonna continue to remain vigilant in looking at ways to create value. We've noted a few considerations on this slide, things again you've heard today. You heard Mark talk about potential shifts in refined products flows. That's one thing that could offer some compelling investment opportunities that could turn us a little away from our capital return focus. It's also possible, as Aaron said, that at some point, transition investments will become more attractive. If that happens, we're gonna look for ways to create value in that space. The crude oil space is improving. There could become a point at some point where we wanna make investments there. For now, the return of capital is really the central theme of our capital allocation story. With that, I wanna talk a little bit about how we think about that return of capital in just a very similar format, just the things on the left side, what are the current features we're looking at that are informing our decision, what that central decision is, and then some things on the right that could cause us to pivot a little bit. Again, they're things you heard today. Again, refined products is a very mature business. It's gonna be needed for a long time, but the growth there is relatively muted. Our core transportation and terminals business is just not growing at a really great rate right now. There's some growth that we can expect, but we don't expect rapid growth. We like our coverage. We like our contract pro-profile. We like our competitive position, but we wanna keep that way. We wanna maintain that good, strong coverage. We're conscious of contract expirations, wanting to make sure we maintain that strong coverage position. We're cognizant of contract expirations when we think about increasing the distribution too quickly. Another factor that we're focusing on is the persistent overestimation, in our view, as you heard Aaron talk about, of the pace of energy transition. We think people are overestimating how quickly that's gonna happen and consequently undervaluing our stock. Secondly, you know, investors have clearly been discounting distribution growth over the last couple of years. It has not been a big focus. We don't hear as much about it. I think investors have been more concerned about maintaining the distribution versus growing the distribution. All those things together lead us to think that incrementally from here, returns of capital above the existing distribution and the little bit of growth that we've talked about delivering consistent with what we did last year. Incremental returns of capital will probably take the form of repurchases. Now, we always talk about caveats around repurchases. We've got those, some of those things over here on the right. I'm not gonna run through all those 'cause we hear them all the time. I do wanna spend just a little bit more time to touch a little bit on our buyback philosophy and be as clear about that as we can. Probably the most important thing to underscore about our approach to buybacks is, it is very consciously not a programmatic buyback program. That is, we're not trying to buy back shares irrespective of price. Instead, our program turns on, in our view, a fundamental value. We wanna create value for our unitholders by buying back shares at a compelling price, okay? When we make that evaluation of whether an investment in our units is attractive, as Aaron said earlier, we're using the same methodical long-term risk-adjusted approach as we have for the entire 20 years that we've been a business, and we've been trying to make intelligent investments. We're using that same approach when we look at our own stock. We're definitely aware of familiarity bias. We try to be as objective as possible when we look at our own business, but we do think we have a lot better insight into our business than we do any other business that we'd be evaluating. With all that, I think it should go without saying that our buyback activities are not focused on short-term impacts on price. We're not just trying to provide liquidity. That should go without saying, but I think given some of the comments and questions that we've seen at times, for example, around, you know, why wasn't there a bigger impact on the stock in 3Q last year when we buy back so many shares? We just wanna make sure it's clear. Well, that's not our goal. If in fact during that activity, the price had moved right away, we would have fired the bank doing the repurchase activity and got someone else to do it because they're not doing their job. So that is not our goal, and we just wanna make that as clear as we possibly can. All right. This next slide is just a long-term chart, the last 10 years of the return of capital that we've provided to our unitholders. The yellow bars there are distributions, the blue are repurchases. I think the thing I just wanna really quickly, you know, note about this chart is return of capital has been a part of our story for a long time. This is not new, right? We've returned $8 billion to our unitholders in the last 10 years. Compare that to our $10.5 billion market cap right this minute. That's a lot of capital we've returned. We've been generating a whole lot of cash, okay? The distribution growth has slowed. It's, of course, not news. It slowed during the pandemic, in particular, but the pace of return of capital has actually accelerated in the last two years. The $1.4 billion we returned last year is over 50% more than we returned in 2019, which is the last year before the pandemic. It's been picking up steam and not the opposite. The $800 million we've repurchased in units so far has allowed us to decrease the number of units outstanding so far by 7%, improving on a per unit basis as well. Of course, the increase in returns of capital in those recent periods is that has been accompanied by significant decreases in typical capital investments, traditional capital investments. We try to be clear. Of course, our preference would be to find more projects that we could grow DCF, and we continue to look for those, but we're gonna be disciplined as we look for those opportunities. Those opportunities are gonna have to compete with other uses of our capital, including against repurchases. While we're always looking, you know, we're acutely aware that one of the fastest ways to destroy value for our unitholders is to do projects or acquisitions that don't meet our risk of return profile. We're gonna be focused on that as we go forward. We're very comfortable being patient and disciplined. If this chart went back 20 years, you would see several years in the first 10 years of our history that look a lot like those last two years, lower capital numbers. A lean capital environment is not new to us, and we're not gonna panic because of that. We know that our business is still healthy. We think we're very confident we can still provide a great return to our unitholders. We're not gonna lose our nerve over that. I'll also say, because we sometimes see comments around this that, you know, people will ask the question, "Well, how much capital do we need to spend to keep our DCF where it is today?" That's just not how our business works. That makes sense in a gathering context, we understand, and it's not as if our DCF can't be hit by things like recontracting and so forth, but it's not as if we say, "Well, how much capital do we have to spend to keep DCF the same?" It just doesn't work that way. That's not the way we think about it. These numbers that you see in these recent years don't scare us. Okay. This slide here is just basically a chart of our financing sources. Again, nothing you haven't seen a version of before. The green bars there are borrowings. The yellow is cash in excess of that was needed to pay distributions. The blue are proceeds from asset sales. The main thing I just wanna get across with this slide is, you know, we've invested $6 billion in CapEx in the last 10 years, but there's no issuance of equity on this slide. There's no bar for that. We didn't leave it off. It just hasn't happened. It's been over 12 years now since we issued equity. Okay, a disciplined, methodical approach, an investor-friendly approach to how we finance the business isn't new, as it's really part of our DNA. Of course, what really jumps off this slide right away is the blue bars to the right, the proceeds from asset sales. That's relatively new. I wanna touch really briefly on that. I think it's just worth contextualizing these recent asset sales and talking about how they fit into our overall focus on value. We've just charted out here our major divestitures over the last several years. I'm not gonna go through each of those individually. Just wanna point out a couple commonalities to all of them. One of those commonalities is in none of those were we forced to do those asset sales. We weren't forced to raise money, or reduce debt, anything like that. We did them because in each case, we believed that executing on those divestitures would create more value for our unit holders than holding the asset. That's why we did them. It's that value focus that informs all those decisions. We're assessing the risks and rewards of holding the asset, and we're gonna continue to do that. We don't have a strategy or a plan of divesting more assets, but we're gonna remain open-minded about the best way to create value going forward. We think that approach, that focus on value creation, being methodical and disciplined in how we finance the company, making capital investments when we find them compelling, refraining from making capital investments when we don't find them compelling, has played a big role in helping us deliver such strong returns to our unit holders over the years. This chart is just a chart of our return on capital invested. We've been showing this chart for five or six years now, at least. Changes a little bit with some of the companies that disappear from the space. We've added a few companies. The overall story has remained the same, which is basically that Magellan has provided the best returns on capital in the space and really by some distance. That hasn't changed. Even in recent years, that continues to be the case. Of course, part of that is just the quality of our assets and the strength of our competitive position. We do think that that methodical, disciplined approach has had an important part to play in that history as well, and will have an important part to play going forward. All right. Having just touched on how consistent our strong returns have been, I spent a lot of time talking about buybacks. I do wanna mention our distribution and take a minute to talk about that. I don't think it necessarily gets all the attention it deserves. This is just a chart of our distributions that we've paid per unit since we went public in 2001. Then the dotted line across is our coverage, average coverage over that period, which has been just a little under 1.3 x over the life of the partnership. Dipped down a little bit during the pandemic, as we all know, but it's come back up a little, and we're near our 1.2x target that we've had out there for a while. Obviously, the rate of growth of distribution, as we talked about, had slowed coming into the pandemic already, and with the pandemic, it slowed further. Nevertheless, last year with our little increase, we were able to notch our 20th straight year of distribution increases, which puts us in a pretty select group of energy companies. Another way, though, we like to look at our distribution, really, and the quality of it, is by comparing what's happened with our distribution and what's happened with other people's distribution in the space over the last 10 years. This is—realize this is kind of a busy chart. There's a lot of lines on here, so bear with me. Forgive those number of lines, but it just reflects the annual change in dividend for us and for our peers over the last 10 years. It looks busy, partly because so many of our peers have had to cut their distribution, in many cases more than once. The lines get kinda jagged. There are not a lot of smooth lines. The majority of our peers have had to cut distributions over this period. There are very few that have been as strong and steady as Magellan, and only one that's had as high a growth over that period. Now, realize this is all history at this point. Of course, you know, you could say that's all in the rear view mirror. We think that history across that period of volatility in the energy space and with the economy says a lot about the resiliency of our assets, and it should give you some confidence about the future as well. All right. Well, of course, it wouldn't be a Magellan presentation if we didn't reiterate our long-standing commitment to a 4x leverage target or maximum, or our commitment to an investment-grade balance sheet. Here's that familiar chart of our historical leverage ratio going back to early days, and that red dotted line across the top being our 4x limit. We finished up 2021 at 3.6x. Again, this isn't some newfound commitment. It's been part of our DNA from the beginning. I don't wanna belabor it too much here. It's something very familiar to you. I just wanna reiterate, though, that we still think that 4x is the appropriate limit for our business, and we think it supports the resiliency, the reliability that our investors expect from Magellan. We think that flexibility that it affords us has benefited us in the past, and it'll continue to benefit us in the future. All right. The last thought, having run through all that, really quickly. The last thing I wanna leave you with here today is just a brief comment here on the total return proposition that we think Magellan offers at this point. We really believe it's a uniquely compelling investment. One thing we should discuss is our yield remains historically high, okay? What we try to show in this little chart to the right, it just shows in green there is our yield going back to 2001, and in yellow is the yield on the 10-year treasury. The spread between those two yields has averaged about 2.5% up until the time of the pandemic. In the last five years before the pandemic, it had widened out a little bit to closer to 3%. Since the pandemic, it's been well over 8% on average, and currently, it still sits well over 6%, okay? That doesn't make a lot of sense to us. We think the only way you can justify a spread that wide is you have to assume, one, that our cash flows have become way more volatile, which as we've discussed all day, we don't think that's the case. We think they're still very, very predictable. Or two, you have to assume a negative growth rate in the business. We don't think that makes a lot of sense either for all the reasons we've talked about. Aaron talked about projections going out to 2050. We think we've got a lot of reasons to feel very confident, certainly about the next 10 years and really longer than that, such that these kinds of negative growth rates that would be necessary to justify this spread don't really make any sense. Okay. With that, in addition to our healthy distribution, its yield now over 8%, you could talk about growth on top of that. I don't want to sell it short. What we've tried to show here, because growth rates, it depends a little bit on how long you're talking about, for example, whether you're talking about DCF or you're talking about growth and distribution, but just using something really minimal, like the 1% growth we delivered last year, or looking at annual assessments, which right now kind of converge around 1%-2%. Either way, you're talking about a total return just without capital appreciation of between 9.5% and 10.5%. We think that's a pretty compelling return, given the stability of our cash flow stream, and especially compared against a market where you see people talking about equity returns being very challenged for the next 10 years given the recent run up in valuations. You can look at different things. We quoted JP Morgan here, who is expecting a 10-year returns on equity of about 4% at this point, and we're offering something like 9.5%-10.5%. Again, from something that's a very proven, stable cash flow based offering. That's all before really taking into account the buyback program, which really brings us back, I think, to the beginning of the presentation. You know, what I talked about from the very beginning, we have a very strong, resilient business. It's generating a lot of cash. We find it really compelling. When we say that, we're not just saying it, we mean it. We're putting our money where our mouth is. We're buying back shares because we believe it. We think with that, we're gonna be able to provide increasing growth on a per unit basis to our unitholders. And we believe that that's gonna be a great investment as we invest in our own shares. With that, I'm gonna stop right on time and ask for questions. Hey, Jeff. It's Spiro again. Hopefully, this microphone works a little better for me this time. Wanted to go back and tie in something Aaron had said earlier just with respect to the different scenarios that he had pointed out and then where the valuation stood, right, obviously towards that worst case scenario. When you do your internal analysis to try and figure out, you know, where you stand there, I guess if it's cheap at that low point, what scenario are you adopting to say that? Then when you think about the metrics, what is that based on? NPV? Is that yield, free cash flow yield, DCF? How do you think about getting to that point? Well, it's definitely NPV. It's present value of a 30-year model. That's how we do it. We really object to and don't like multiples for yields. We think that's bad work, Frank. I mean, we all have to get by. You know, we got to give answers real short, real quick, but we're taking our time and doing it right and looking at long-term cash flows. First of all. Second of all, in terms of where we draw that, I wanna make sure that was as clear as it could. That lower left, the sort of the lowest value there was based on that Wood Mackenzie case. We're trading well below the value we calculate in that case, okay? If you had to ask us exactly where we put us amongst those different scenarios, it's a little bit academic because right now we're below the worst scenario that is on our page. We haven't, frankly, had to wrestle very hard recently with exactly where we are on that. When we do that, we'll do it the same way we do everything else. We'll be looking at risk and reward and thinking about it real hard. You know, Aaron was as careful as he could be. We don't have a crystal ball. We don't know exactly what it's gonna be. We're just gonna bring that same risk-adjusted, long-term focused, and Net Present Value-focused approach to it and try and make sure. You know, when we do an investment, we try and look for multiple ways to win. We don't look for it to be, like, really wound tight, and it has to go exactly the way we expect it to for it to be valuable. So we're probably gonna be fairly careful on that. That's one thing I think people have to be careful. I know people are kinda anxious. What is that fair value that the company has? Well, you know, what our fair value is may be, you know, built in with a lot of risk and concern and caution in it, because that's the way we approach a lot of investments. We're gonna be careful and methodical. Just because we stop buying doesn't mean we've reached, you know, a point where we think the value is inappropriate. I'll stop there. That's a conservative approach to acquisitions, and we're using that same approach with us. It's helpful. Thanks. Second quick one. You know, I know you addressed this in the past, which is in thinking about C-corp conversion, just wondering where your thoughts are there. There's more uncertainty than ever, so good luck with that question. No, I mean, our thoughts haven't changed very much. I mean, there's a couple of new data points. There's 12 more months of history or whatever, maybe 14 months of history. We continue to watch those. I still don't think any of them are super great comps or compelling. There's always noise on those stories. I think the most important thing I'd say is we continue to watch that and listen to unitholders, particularly, who, you know, ultimately, it's their investment, and we wanna do what everybody really wants. The fact is, we don't hear a lot about that from most investors most of the time. I think most of the time you hear about it is in, honestly, it's analyst comments that are talking about what could be a catalyst over the next six months. We're thinking about what is gonna create value for years and years to come, and that's where we come up against the tax situation. Again, we continue to listen to the interests that people have in that topic. We continue to pay attention to the data points, and we're open-minded as to what ultimately would be the best answer. The analysis we've done really hasn't changed so far. Thanks. The company's been a pretty active seller of assets over the past few years. When you look out now, do you still see potential to potentially sell other assets in the portfolio, or have you kind of achieved what you wanna achieve on that front? I'm just thinking some of the assets like, I mean, you have a lot of storage at Cushing, for example. I don't know if that's completely core to the company, but I don't know what type of price you would get for that. Just how you're thinking about asset sales from here, and are we kind of towards the later innings of that or are there still opportunities do you think the next few years? Yeah. I don't think there's a really super bright line answer there. I will say we've been careful to say this along the way. The transactions we've done so far had to do with less core assets. You know, you could argue that we're some way into the game already and there's less than there was. There's less that's non-core. That being said, while we don't have a program, it's not like we've got a goal of selling some more assets by such and such by such amount of time. Nothing like that is in place. We're open-minded, and we're trying not to be wed to assets or emotionally attached to assets. It's all gonna be about that value arbitrage. If someone else puts a higher value on it than we do, we're gonna look at it. That's an open-ended question. I do think it's less likely than it was two or three years ago when we had some more non-core assets, but I wouldn't say that we're done, and it couldn't happen from here. Anybody else? Yeah, Theresa. Hi, Jeff. I wanted to ask about the strategic view on getting more downstream. Just following up on Robb's comments about, you know, possibly operating or taking the marketing and processing risk for the condensate splitter in addition to operating it, as well as Mark's earlier comments about, you know, building renewable diesel processing capability. How serious are these discussions? How far along are you on this, and what's your general strategic view on getting to that part of the value chain on both the petroleum and renewable side? Well, short answer, it's early days, I think on both of those. We wanna be prepared to do either one of those if that's the best way for us to adapt to the circumstances we find ourselves in. We are doing the work. The second thing is I would just kinda push you back to, we love stable, predictable cash flows. Our first preference is always gonna be to find a contract structure or business model that's gonna lend itself to that. We're not, you know, trying to get downstream per se. We'll be looking for opportunities to maximize value, though, whether that's operating it for somebody else or operating it for ourselves in the case of the splitter. In terms of renewables, that's evolving pretty quickly, and so we're just gonna have to stay nimble on that. You know, I think I relate it back to one other question we got earlier, too, and I think it was Gabe's question about our risk appetite and around looking at new things and, you know, we've been conservative, and is that gonna change going forward? You know, conservative is kind of probably not a very precise word. I think the way we really think about it is risk-reward balance. I like to remind people, you know, when we bought Longhorn, there were no cash flows on that asset, zero. We sat there for six months and had people who would dial in on the call and say, "So how's it going on Longhorn?" We'd be just kinda sweating. We're like, "It's coming." You know, "Trust us, we're gonna get something there." There was a lot of risk when we first bought that asset, but we could see the return potential, and we knew there are lots of ways to win with that asset across a great piece of real estate. We're willing, we've long been willing to take risk when we see the risk-reward profile and balance in our minds. Doesn't mean there won't be some risk, but if the rewards are good enough, we're gonna be willing to take those risks. Okay. I'm gonna stop there then and let Mike come back up to make some closing remarks and take any other final questions. Thanks. Good job. We actually finished a couple minutes early. I'll just maybe take an opportunity if anyone has any final questions before we close. I think you probably got them all out there, but just wanna make sure. Oh, I knew, I knew I'd have one taker. Hi, Mike. I don't have a question. I just wanted to say congratulations on the retirement, and you've built a really great company. Oh. Well, thank you. Thank you very much. That wasn't a setup, by the way. I'll be brief. This is my last time to be in front of you. I've been very blessed to have a 37-year career with the company and 11 years as CEO. It's truly been a blessing. I'm proud of the company and the people and the culture and the performance of the company really over that entire timeframe. One of the things I've enjoyed about that is these kinds of meetings. I mean, it's probably primarily because we've always had a good story to tell. It's been enjoyable to talk to investors and talk to analysts, so I will miss this part of it. Thank you. Thank you for coming. Thank you for your questions today and your attention. We've got lunch following. Everyone's staying, so if you have additional questions or you just wanna socialize with the management, please stay for lunch. Thank you again.