Okay. We are back. Very happy to have Kinder Morgan here with us. Kim Dang, CEO, to my left, and next to Kim, Chris Gratton, Treasurer. This is being webcast, so for the Q&A, just wait for the microphone, please. Thanks. So I don't know if you want to make any opening remarks or just jump right in. No. All right. Great. Well, thanks for being here. There's a lot to talk about. I thought maybe we'd just start with the elections. That seems kind of top of mind. Maybe you could just give us your high-level thoughts on how you see the change in administration impacting the company, the industry writ large, just how you're seeing things. Yeah. By and large, I think it's very positive. One, we have the LNG pause right now, which I think gets removed very early in the next administration. And so I think that's positive to the long-term LNG development story in the U.S. I think on the tax front, there's some debate about the timing, the exact timing of the tax bill, whether it's going to be one bill altogether or whether it's going to be a second separate bill. But there should be some positive things in there to the extent that they extend some of the 2017 items, such as bonus depreciation, would obviously be a positive. There's an interest deduction limitation that went from EBITDA to EBIT to the extent it goes back to EBITDA. That could be a positive for us. There's a minimum book tax that came in during the current administration. You could see some changes to that that potentially could be a positive. I think there's also the potential for reduced regulation, and that could impact us cost or time or both. Exactly how that impacts us, I think, is going to be in the details of what the reforms look like. So it's hard to speak to that today. But I think permitting reform could obviously be part of it and to the extent there were some things there. I mean, you really got to get into the details on permitting reform to see whether there's a big impact. And then the tariffs, obviously, that's something that all companies are watching as we are. And right now, most pipe is rolled in the United States. The Trump tariffs from his first administration, the Biden administration left on, and so they're still there. So most of the pipe you can get in the United States. Great. Thanks for that. I'm sure you're going to be shocked to hear that I'm going to have some questions for you on data centers. Maybe just start kind of high level. You have quite a network of pipelines. So where are you seeing regionally the most opportunities in that area? And I brought it out beyond data centers to just where you're seeing new pockets of gas demand that you think you have an opportunity to invest? Yeah. And I think that's a great point, Michael, which is the data center is just one piece of the power story. We are seeing increased power demand as a result of coal conversions. We're seeing it as a result of population migration across the Southern United States, industrial development in primarily the Southern United States where you've got more friendly business climate, the onshoring. And so you're seeing things like chip manufacturers, battery manufacturers out in Arizona, in the Desert Southwest. You're seeing automotive plants built in the Southeast. Obviously, in Texas, you're seeing a lot of industrial development. So the power story is quite large. When we look at natural gas demand, Wood Mackenzie projects natural gas demand in the U.S. to grow overall at about 20 BCF a day over the next five years. In that number, they have embedded negative one for power demands. We don't think that we absolutely think that is incorrect. We've seen Wood Mackenzie numbers that talk about 10 BCF a day of incremental gas demand for power. Now, they'd be the first to admit that that's an optimistic number. But if you take that negative one and say it's five or six of incremental power demand, all of a sudden, the 20 BCF a day of growth in natural gas demand goes to like 25 plus BCF a day. So I think it is a big part of the gas growth that we see coming in the United States. And so I named a couple of places that we see it. But on the data center side, you see announcements from Meta that they're developing a big site in Louisiana, a $10 billion site. And I think Entergy is going to provide the power on that one. You've seen one in Mississippi that Amazon has announced. It's also $10 billion. You just saw we got a big expansion into the southeast that we have signed up, a $3 billion project. That is largely power demand, but we don't think specifically related to data centers. And so I think just lots of opportunities to expand on the power side. And based on, given our asset base, seeing it across the Southern United States. Great. So definitely a bunch of follow-ups there for you. I guess the first is just, would you say that most likely most of the investment you're going to make is front of the meter, meaning you're going to be expanding capacity to the utilities or then broadly increasing power on the grid to satisfy data center, but also all the other things you talked about? Or do you think behind the meter is something you're also looking at? Yeah. So it doesn't so much matter to us if they build the power plant in front of the meter or behind the meter. What matters to us is, is there incremental power demand for natural gas? And as long as there's incremental power demand for natural gas, and assuming that we have pipelines in the vicinity, that's going to be an opportunity for us. So we're a little bit more agnostic to whether it's behind the meter or in front of the meter. Just any incremental power demand is going to be a positive for us. And then from a returns perspective, how does that, I guess, A, what do the returns look like relative to your typical returns? Are they better, worse, the same? And then again, same question, like behind the meter, front of the meter, does that make a difference on returns? So if you think about our returns, the way we approach it is we sort of have a minimum threshold for a certain type of project. That's based on the risk return that we can receive. And that's well above our cost of capital. So we've got a nice decent margin there between our minimum level of return. And then based on the risk of the cash flows, the returns go up from there and they vary. So one end of the spectrum, we would take a return that's at the lower end if you have 20-year take-or-pay contracts from a creditworthy party. On the other end, if you had something like a CO2 investment, you're going to require a much higher return on that just because there's more risk in the cash flows. And so there's multiple different things that they can drive where those returns end up. Sometimes you have customers that power or their energy costs are a huge portion of whatever service or product that they're providing. They're absolutely going to be more sensitive than somebody who's it's a small portion. I mean, just think about it. When you go to 7-Eleven, if you're going to buy a piece of candy, are you thinking about, is it 10 cents more? Is it 20 cents more? I mean, you're probably not going to be as price-sensitive on that. But if you're buying a house, which is a much bigger portion of your budget, you're going to be more price-sensitive. So it depends on the customer. And also, it has to work for their economics. So there's customers that have approached us in the past that want something, and we can't deliver it at a cost structure that makes sense for them. And so they're going to be very price-sensitive. So it's very situation-specific, and so it's hard to describe the exact returns. But our methodology doesn't change. We've got the minimum level. We vary the return above that depending on the risk of the cash flow. And sometimes we can do better than where our minimum returns that we would target based on the risk in that cash flow. And sometimes we're right at the minimum returns, but always well in excess of our cost of capital. Yeah, and I think the other thing would be just the competitive nature of where you are. If you're in an area that has more competition, then that can definitely change the return profile that you might see. Okay. Quick question over there. If I could just go back to the comments that you made on front of the meter, behind the meter. So I think some of your peers, Williams and TC Energy, are looking at kind of holistic solutions behind the meter where they would bring the gas, supply it, build the power plant with some of the turbines that they use for compressors. And deal directly with the data centers that way. Is that something that you would be open to or looking at, or is it kind of more focused on working with the utility and aggregating it that way? Yeah. I think it's largely more focused with working with the utility. I'm not saying that's something that we would never do, but we did build power plants once in my lifetime at Kinder Morgan. And that is not where our core competency is. And so we're good at building pipelines and bringing those in service. And we strive hard to do them on time and on budget. And a power plant's just a totally different animal. And so if we could get the right structure where we had an EPC contract and where we weren't taking the spark spread risk, taking spark spread risk is not really our business either. So if you had a long-term offtake and you had an EPC contractor, is it something that we consider? Maybe. But I think there's a lot of people out there that are going to be more competitive building power plants than we would at Kinder Morgan. Now, there are other things that we can consider, like if you have land and it's next to a storage facility, could you contribute the land and get some type of interest in the power plant and try to structure that so it wasn't as commodity sensitive or it was an all upside? I mean, I think that's something that we can consider. But generally, we're good at building pipelines, and that's the business we're going to focus on. Just ask another follow-up on the previous question. So Mike asked about the returns that you get on projects, and you kind of mentioned you kind of gave the framework that you've been using for the last few years, which is this is our cost of capital. And depending on the risk of the project, we'll price above it. But have you seen because we have heard? No, we'll price above it, not just depending. Yeah. But have you seen it feels like with all this gas demand and competition for space on pipes, you have more negotiating power. And have you seen that spread increase over time, or do you have the ability to charge more on some of these negotiated rates? Yeah. It's totally project-dependent, right? And each project is unique. And so you have to look at, to Chris's point, the level of competition. It's going to be customer sensitivity to price, which gets to do they have to get it approved at a commission? Is it a big portion of their cost structure? It gets to how you structure that contract. Are you going to do cost sharing on the pipeline side because you're concerned about some risk? So that could cause the return to vary. So there's a whole host of factors. I mean, at the end of the day, we're trying to get the best price that we can get, right? The highest price that we can get, working within all the constraints that are out there, but always making sure that we are clearing our cost of capital plus a spread because projects have risk. We're not doing things down at our cost of capital where if you have a small problem, you could be below your cost of capital. We make sure that there is a spread between those returns and where our cost of capital is. Maybe if we just sort of stay on this topic. I wanted to talk a little bit about the Texas market specifically because it seems like there's going to be a lot of data center demand specifically in North Texas. And you have one of the largest intrastate systems. So I guess my question is, it's another question about returns because it's an intrastate system. So maybe the returns could be different than a regulated return. And I don't know. And also just, do you have excess capacity in that system? Would you have to expand? How do you see the opportunity in Texas from your perspective? Yeah. I mean, Texas is a great market. And Texas is a great market because it's largely unregulated, as you point out, and because we've got a great footprint, as you also pointed out. So it is a fantastic opportunity for us. Most of our pipelines in Texas are running near capacity. And so it's going to be more about expansions than it is filling up the existing system at this point. And if you look at our five largest pipeline systems just across the United States, we're running at like 87% usage factor, right? And that's up from like 73%, I don't know, seven years ago, something like that. So what's happened is the natural gas market's grown 30 BCF a day in the last eight years. And then we're expecting, as I said, 20- 25 BCF a day of growth over the next five. And so that 30 BCF has taken that capacity margin up to the 87%. And if you look at that, you say, "Oh, well, you have 13% more capacity." But in the natural gas market, you've got seasonality. And so in the winter and in the summer, you're really peaking up. So if you're running 87% on average, then you're really largely at capacity because you've got to build capacity for the peaks. So I'm not saying there's no place that we can take incremental demand, but just at a very high level, I think it's largely going to be dependent on expansion projects to add those incremental volumes. That could be large expansions. That could be smaller expansions. Some of it may be about extending a small piece of the main line and then building a lateral off. So that could be a smaller. It could be something big like the SNG, where we're expanding a significant portion of that main line and adding compression, which is a $3 billion project, so those projects can really take different shapes and sizes, but the Texas market overall, we serve 40% of the power demand in Texas, and it has all aspects of the natural gas demand growth. It's got power. It's got exports to Mexico. It's got LNG exports, and it's got industrial growth, so all the big drivers of natural gas demand are present in Texas, which is part of what makes it a great opportunity. Another kind of element to this, so maybe I'll give ourselves a quick commercial. We launched a new report on Monday tracking all the open seasons that are out there for natural gas pipelines. I wonder if you could just maybe refresh us a little bit on the process in terms of are you first negotiating with customers, and then you have some already effectively lined up, and then you go to the open season, or how does the open season process work relative to when you end up announcing or press releasing a new project? Because that's clearly the dynamic that's starting to happen now. Right. So unfortunately, I wish I could give you a rule of thumb, but each project is unique, and let me give you a couple of different examples of that, so on some projects, we think it's important to have a foundation shipper. And so we will go and we're working with really one shipper, and we think there's incremental demand out there, but we think it's important to have the foundation shipper. So we'll sign up a foundation shipper before we go out and announce an open season and then build momentum from that foundation shipper. There are other projects where maybe we're not working with one party. There's a bunch of different parties out there, and because there's a number of different parties, we don't necessarily think we need foundation shipper. The dynamics aren't similar. So we will just announce the open season and then get people to sign up in a binding open season, and at the end of that, we're ready to go. There are other examples where we finish the binding open season. We're working with people, and we think we should extend the binding open season, and so we do an extension of the binding open season to allow us to finish working up contracts, and then we announce that the project's successful. There's also cases when the binding season closes, we're not done. We're still working with shippers, but we don't think it's necessary for regulatory purposes or commercial purposes to extend an open season, and so we just continue to work outside of an open season with the customers on getting firm contracts signed, and then there are other cases where we announce the open season. We don't get the demand that we need. Open season closes, and we don't move forward with the project. So I mean, just depending on the commercial environment, the regulatory environment, and when commercial, I mean competitive as well, because sometimes it's about getting an open season out there in front of your competition or in line with your competition. It just varies. It's very unique to every project. Maybe the next logical pivot is to growth CapEx. So you put out your preliminary guidance for 2025. I have probably a few questions in here, so I apologize. I guess one is, what does the backlog look kind of beyond that, what you've announced? In other words, is there a chance that this is what you've put out there as guidance is what is sort of already identified and definitely happening? Whereas is it possible throughout the year that number could creep higher as you sanction more projects? I guess that's kind of number one. And then in terms of where do you think that over the next few years, let's call it three to five years, do you see that number, kind of that annual number trending higher given the opportunities that we've been just talking about for the last 10, 15 minutes? Okay. Sure. So the guidance we put out yesterday, market close, 2025 expansion CapEx budget is $2.3 billion. The annual guidance that we've been giving people is we expect to spend around $2 billion-ish a year. And in my mind, that could be $2.1 billion, $2.2 billion, $2.3 billion, $2.4 billion, or it could be $1.9 billion, $1.8 billion, right? I mean, so it's a very rough order of magnitude to give people a sense for where we'll be. I think that when we build our CapEx budget, we largely build that with projects that are already sanctioned or that we think are imminent, if you will. And so we think it's likely that they'll get signed up probably by the first quarter. Anything beyond that, we don't try to include in our guidance. The $2.3 billion, about 80% of the $2.3 billion is in natural gas. So the biggest chunk of our spending is in natural gas. Natural gas is roughly two-thirds of our overall business in terms of EBITDA. So spending a little more in natural gas than it is an overall percentage of the business. When we start and take a step back and look at the longer term, again, as I said, the number right now that we've guided to is about $2 billion a year. You're asking, could that go higher? And the answer is maybe, right? We continue to look at that. Right now, the backlog is sitting at about $5 billion, give or take, of capital. And that comes online generally within one to three years. And so I think as we add to that backlog, depending on how that shakes out, we will look at whether we need to update the $2 billion per year number. The other thing I'd point out is that the timing of the spend matters, and we've got a portfolio of assets that has the projects have different timing of spend, and what I mean by that is when we're doing gathering and processing projects, it's not a huge portion of our business, but those projects are typically quick to market, so you sign a commercial agreement, those things are typically going to be in service within 12 months, and so that spending is relatively near-term from the time that you sign a commercial contract and service. When you look at projects that we do like intrastate, so within a state, those are typically, and I'm just giving you rough order of magnitude that you can try to use as a rule of thumb, those are usually two years, right? So you get a commercial agreement, you go out, you do your right-of-way acquisition, you construct. It's usually two years from the time you sanction the project to the time you bring it to market. And then when you do an interstate that is FERC regulated, that's typically more like a four-year process where the first two years you're spending in the regulatory process and the last two years you're spending building the project. And so given the different mix of projects, that can tend to spread that CapEx over time. And so that's something we also take into account is what we think the mix of projects is likely to be as we guide people to what our future CapEx looks like. Maybe just on that, you have Mississippi Crossing and Trident, both of which are very chunky projects, and probably there'll be more. But you can quickly start to, I mean, I know they're kind of later dated in terms of when they would come into service, but you can quickly kind of stack these up and get to over $2-3 billion. Is there a maximum number on CapEx that you wouldn't go above? Because if you saw the opportunity set was big enough and you could do $2 billion of these high-return projects, is there conceptually some number you wouldn't want to go beyond free cash flow after dividends negative or not go to a point where it raises the leverage ratio? Sure. Okay. Let me talk about Trident and Mississippi real quick. Trident, if we're successful on these, Trident is intrastate, and so it's going to be on a two-year timeframe. Mississippi Crossing is going to be a FERC project. It would be more on the four-year. So that'll spread out the timing of spend on those two projects a little bit. But in terms of thinking about how we finance all this, this year, distributable cash flow is roughly $5.3 billion. You look at what our dividends are, and you've got $2.5 billion, give or take, that we could spend on CapEx, so expansion CapEx. So the way I think about it is horseshoes and hand grenades. We've got $2.5 billion of cash flow that we can use to internally fund growth projects. So we have some room between where we are and what we could theoretically do. The 2025 budget has us ending Debt-to-EBITDA year 2025 at 3.8 times. Our balance sheet target range is between 3.5 and 4.5. And so we are on the lower end of that range. And so we do have some balance sheet capacity should we need it to be able to fund those projects. Now, I think that we worked a long time to get our balance sheet here, and so we're going to be very disciplined in how we use that balance sheet, but we do have some capacity there that we could use if CapEx went higher. And then the other thing I would point out is that I think there's plenty of third-party money that if a project was really big such that we didn't want to take all the risk on a project, or if the CapEx in any given year was so significant. I think there's third-party capital that's attractively priced that we would still be able to sanction a project, go out and get external capital, and be able to pursue that project. Thanks. How do you think about your dividend policy now going forward? Sure. So with the opportunity set that we're talking about here, I think we want to be conservative in our dividend policy because I think we want to maintain flexibility to be able to fund these capital projects out of cash flow. And so I think we'll have, and you saw that this year, we announced that we expect a dividend of $1.17, which is a two-penny increase. I think it's important to increase the dividend because we do have dividend-paying focused investors in our stock. And so I think it's very important to increase the dividend, but to do it in a way to maintain flexibility. So if we're going to talk about increasing the dividend more, I think that's a conversation for when we get through the big backlog of capital projects and you start to bring this cash flow online and create more capacity, then I think there's an opportunity for that conversation. The other thing is right now we're not paying cash taxes. At some point, we're going to pay cash taxes. If we get some of the tax benefits that we're talking about, hopefully that can move out in time. But that's also a consideration that we take into account as we're considering dividend policy. Maybe just to round that out, how do the other segments compete for capital with natural gas right now? And I guess specifically the energy transition, like RNG, for example, which I don't think has necessarily hit your return thresholds every single time. So how do you think about that? And then within this conversation about living within guardrails, CapEx, free cash flow, do you revisit any of the segments about divestitures? I know obviously there's the long history. We've both been doing this a long time around CO2, so that's always been one that has come up in the past. So how does that kind of all fit together? Okay, so I'll start with divestiture and capital allocation and RNG. Those are your three questions, right? Yeah. All right. So on capital allocation, we've got a very defined set of criteria. And again, I've explained it. We've got the minimum, and then we vary from there. And the way that, let's say that it's a product, I think the way you handle it there is if you think there's more risk in the terminal value on products or you think there's some likelihood could demand, does it decrease, does it increase, what's happening on demand, you're going to run a shorter cash flow period. You're going to run a more conservative terminal value. But if it clears the hurdle, it's going to get funded just like natural gas will get funded. And at this point in time, we're not having to ration capital. And so they are living within the same parameters that all our business segments are living within and the natural gas is living within. And everybody's kind of aware about, okay, I need to make these assumptions and I know what the return thresholds are. So you don't see a lot of projects, we don't see a lot of projects coming in that we're just not going to do. Generally, people know what the thresholds are and they're bringing in projects that are going to get approved or that they want to have a conversation about because it's close. And so I don't think no one starved for capital or saying, "My business, I can't get capital for it, and so I just don't see this as a great business." Those terminals and products businesses are good businesses and they've got inflation escalators in the tariffs. It's a very nice, stable cash flow business for us that's pretty low on a capital intensity basis. RNG, I know you'll probably find this shocking, but the returns are still where we need them to be in terms of above our cost of capital. They're not where we wanted them to be. The projects themselves are very profitable, again, not where we wanted them to be, but well, well above our cost. It's just when you roll in the acquisition premiums, then you get down to something that is closer to the threshold, whereas we had targeted to be much well above the threshold. Those projects are okay, but they didn't perform up to our expectations the way that we've taken a pause on doing some of those till we can get the ones that we have under construction online and operating. We've got three of four online and operating. The operating ones are doing pretty well at this point. We're understanding how the operations work and they're humming along. So the way that we've taken a pause. We're making sure we got our lessons learned. Then I think when we're looking at new plants, you're just a little bit more conservative in terms of what does it cost and how long does it take you to get this thing up and running. And I think that's the way we've handled it internally. With respect to your divestitures question, I think the businesses that we own are, with the exception of CO2 oil and gas because the CO2 pipeline business, they all have a lot of similarities. And so there's synergies in owning them together. I mean, we have one project management group. We've got one pipeline integrity group across all the businesses. And so we are able to have centralized services, and that allows some synergies in owning these together. You can have some similarities in regulatory environments that help you more easily understand these. So they're good cash flow assets. Again, we like the inflation escalators and the products and terminals business. And so there are dyssynergies taking them apart both on the cost side and then potentially on interest. And owning all these businesses together gives us opportunities for conversion. So we've converted product pipelines to natural gas and natural gas products to crude and crude products to NGLs. So there's opportunities as a result of owning different pipelines. So on the CO2 business, it's a relatively small portion of our business now. It's 7% of our business. We make great returns on that business. There aren't a lot of people who know how to do that. Last time I looked at the projects, I think every project, what, one was well above 20%. So it's not like we're just hitting the minimum thresholds there. Most of them are really nice returns. So I think that's a business that we'll continue to own. But we are rational economic creatures, and so our businesses are for sale every day. If we get the right price for our business, we are happy to sell it, take the cash proceeds, and redeploy them into higher returning projects. I think the only thing I add to that, which is, I think, fairly odd from what Kim said, is in those products and terminal segments where you've got that very consistent cash flow, there's not a whole lot of CapEx investment that we're having to make in those businesses. So basically, you're getting the cash flow off those that are allowing us to then redeploy that capital as it sits right now into more of those gas projects that we have.