Welcome, everyone, and good afternoon. My name is Theresa Chen. I'm the midstream and refining analyst here at Barclays. It is my pleasure to introduce our next company, Kinder Morgan, and with us is Kim Dang, CEO. Welcome, Kim. Thank you, Theresa. Thank you for being here. So I'd love to begin by getting your views on the macro backdrop on natural gas demand specific to power generation for data centers, which I'm sure is a question you've been entertaining for the past few months. So you've previously talked about ongoing commercial discussions on over five Bcf per day of opportunities related to power demand, of which one point six is directly related to data center demand. Can you talk about Kinder Morgan's strategy within this theme? And how do you view KMI's positioning here relative to your peers? Sure. So, you know, on the second quarter call, we talked about five Bcf of power demand, of opportunities that, you know, we've got lines in the water on. And of that, the 1.6 that you mentioned was the data center / AI demand. And the reason we mentioned the five Bcf is because there's been a lot of focus on the data center demand on the AI demand, and really, that's just a piece of the overall power demand that we're seeing at Kinder Morgan. And so that was just a way to help people understand, hey, it's bigger than just the data center AI demand, the power piece. It's a lot bigger. And you know, it's being driven by a number of different factors. It's being driven by, you know, migration, population migration into Florida and the Southeast markets and Texas and Arizona. It's being driven by businesses moving to those areas because of lower taxes or less regulation. It's being driven by onshoring, right? So the CHIPS Act, you know, you're seeing a lot, you're seeing chip factories built in Arizona, battery facilities being built in the desert Southwest. You're also seeing some of the ISOs wanting to increase, you know, the margin of error with respect to their capacity relative to demand. You know, in Texas, the peak demand in 2018 was 70 GW. And this summer, the peak demand was 86 GW. So you had a 16 GW increase in peak power demand since 2018 in Texas. And I think that's indicative of what a lot of these states are seeing, you know, in the Southern states. So, you know, shoring up reserve margins, you know. Texas has out there. They're going to subsidize 10 GW of power development, and they're talking now about maybe they need to go to 20 GW. You also have demand for natural gas from power plants that are being built south of the border in Mexico. There's no incremental gas supply in Mexico to serve those, and so that's going to have to be supplied, you know, out of the U.S. So I think there's just, you know, enormous power demand. There's coal conversions. Still, we're seeing, you know, Kentucky and Tennessee coal plants converting to natural gas. And so all those are playing together just to you know, to create a nice growth in the power markets. So, you know, at Kinder Morgan, we move 40% of U.S. natural gas. We serve about 20% of the power demand across the United States, and we serve about 40% of the power demand within the Texas market. So it's going to be a nice opportunity for us, moving into the future. Got it. You know, I'd say the other thing is, you know, the first evidence of that on the South System 4 project that we announced recently. Yes, that tees up my next question very well. Specific related to the SNG expansion, can you provide some color on how this came to fruition? And of course, there's been some, you know, scuttlebutt out there of whether this is going to go forward or not. Remind us, these are binding co-commitments, if that's correct. And what should we look for as far as next steps, timeline, and key hurdles to watch for from here? Sure. So as you know, but for some people who aren't as familiar with our system, we've got our SNG pipes, Southern Natural Gas, 4.4 Bcf a day, that moves gas primarily into markets in Mississippi, Alabama, and Georgia. And those, our customers in those markets, you know, have been seeing what everybody else has been seeing in terms of increased demand for power as well as increased demand for natural gas. And so we have been in discussions with them about a potential expansion. We held an open season late June, early July. We have 1.2 Bcf a day of commitments signed up. It's a 3 Bcf a day project. You know, our existing system is full, so this is about looping our existing pipeline system, primarily on existing right of way, and then also adding compression, primarily at brownfield compression sites. So we expect in-service to be late 2028. You know, horseshoes and hand grenades. It's kind of two years to get, you know, to get all the regulatory approvals filed and get the permits, and then two years to build. And so, you know, I think we'll target making a FERC filing probably sometime next summer. Great. And then in terms of the estimates between the base case of three to 6 Bcf per day incremental natural gas demand by 2030 for data centers, versus your upside of 10 Bcf per day, can you give us, like, a sense of what drives the delta between the two? And, you know, realistically, based on where your assets are situated already, what kind of market share can Kinder Morgan capture? Sure. So the 3 Bcf-6 Bcf is data and AI, right? And so we don't have a Kinder Morgan estimate really on overall power. That's just our estimate on the data AI piece. So if we back up and we look at natural gas demand, that Wood Mackenzie's projecting, they are projecting natural gas demand to grow from 108 Bcf a day and to 128 Bcf a day by 2030. And that growth is made up of 15 Bcf a day coming from LNG, 3 Bcf a day of growth coming from exports to Mexico, and 3 Bcf a day as a result of industrial demand, increased industrial demand. Embedded in that number, in the 128, is a 4.5 Bcf a day decline in power, okay? And so we, you know, for a long period of time, we have been thinking that, you know, Wood Mackenzie's been underestimating, you know, the power demand, and we certainly think that at this point. I think relative to what we see, they see, you know, more renewables taking hold and taking out some of the natural gas. You know, we don't see that same, you know, we don't have that same view. McKinsey Consulting, I recently saw a number from them, and they were projecting about 10 Bcf a day growth in overall power demand, you know, that's versus a 4.5 Bcf a day decline that Wood Mackenzie's projecting. Then our number, again, on the piece of that that is data and AI, is 3-6. I have also seen numbers as high as 10 Bcf, not our numbers, but some external third-party numbers, as high as 10 Bcf on the data AI piece. But again, I think with you know our share of the power market both you know in Texas and based on where a lot of this development's gonna occur, I think it's gonna create just great opportunities for us. And part of that's as we discussed on South System 4, but I think there'll be plenty of others in the future. Understood, and then maybe turning to the supply front. Okay, so would love to get your views on the supply picture in the near term, as well as the medium to long term, and just given the expansive geographical reach of your natural gas assets, any color by region in which you're situated would be helpful as well. Okay. So again, we generally use Wood Mackenzie. And so what they're projecting is on the supply front, to fill the 20 Bcf a day of demand that they expect, is about 8 Bcf a day coming out of the Permian, 7 Bcf a day coming, and this is again between now and twenty thirty, 7 Bcf a day coming out of the Haynesville, 5 Bcf a day coming out of the Marcellus Utica. And then on the Eagle Ford, it's like 0.5 Bcf a day of growth. You know, our view relative to that is, I think we would expect probably a little bit less growth coming out of the Marcellus Utica, just because of the constraints on getting incremental capacity built out of there, and probably more growth coming out of the Eagle Ford, given how close it's located to all the expected demand growth, and so you know, we are very well positioned to serve. You know, we have some gathering in the Haynesville, so that's gonna be a great market for us. We've got a huge position in the Eagle Ford. Again, I think there'll be more growth than the 0.5 Bcf. And then obviously, we've got some big pipes coming out of the Permian, although they're largely contracted, but I think, you know, that's potential, you know, we have potential for a GCX expansion coming out of the Permian. Great, which leads to my next question on Permian residue egress in particular. You know, with the recent FID of Blackcomb, with that project moving forward, does that have any impact on the commercialization efforts for the GCX expansion as it stands today? And maybe just more broadly, if you can comment on why it seems that producers have taken, you know, longer than expected to sign up for commitments despite the steeply negative pricing that they're experiencing right now. Sure. So on GCX, look, I think that's something that's gonna get done, you know, at some point. In my view, that's more about when, not if. You know, I think it is. It's got a nice, an attractive tariff on it. Fuel's a little bit higher because we are really compressing up that pipe to make that potential expansion happen. And so fuel is a little bit higher, and so that degrades a little bit of the attractiveness relative to a new build pipe. But I think it's relative. I think it's an attractive proposition for shippers at some point. I think that, you know, why a new build versus GCX? I think, you know, there's a view, given the growth coming out of the Permian, that people wanted to see a bigger pipe built out of there. And so, you know, I think shippers put their weight behind having, you know, underwriting a bigger export opportunity. But again, I think, you know, at some point, somebody, shipper's going to come, and it's going to be attractive capacity for them to take, especially given the continued growth that we see coming out of the Permian. You know, why it takes longer? You know, I don't know. That's something we've been saying for the last twenty years, so that, you know, the basis differentials typically, you know, blow way out before people end up signing up for capacity. You know, you have to look at it from the E&P's perspective. You know, they're taking on a big commitment when they sign up for ten years, and so I'm sure they want to make sure that their projections are good and that they're signing up for the right amount of capacity, and I also think, you know, more recently, you've had a lot of M&A opportunity on the E&P side, and so, you know, it probably takes some time to sort out, you know, what the combined company is going to need, so there's a couple of different factors that are probably playing into that. That makes sense. And then against this, you know, volatile, pricing backdrop for the, outlook, on natural gas prices, plus robust, you know, anticipated demand growth, how do you view the value of your natural gas storage assets, much of which are under market-based contracts, right? So, do you see additional, you know, attractive opportunities for brownfield or greenfield storage projects, within your footprint? And any commentary on the base assets as well. Sure. Look, I think storage is going to be a great opportunity. And if you look at it, so the natural gas market has grown by, you know, 30 Bcf a day, 2015 to now. That's like, I think it's 39% growth in the natural gas market. You've had about a 1% increase in storage capacity, maybe a little bit more, but not a significant increase in storage capacity. And then the other thing that you've seen in the market is that you're getting more and more volatility in the demand curves. And so historically, the, you know, storage was used, pulled on in the winter, you know, for seasonal reasons. You inject in the shoulder season, then you pull again in the summer, and you inject in the fall season. And so it was really all about, you know, about weather, and in the summer and the winter seasons. Now, you know, you've got a couple of other factors that are contributing to more volatility. You know, one is the renewables. And so, you know, I'll use Texas as an example. Texas, in 2023, about 30% of the power stack came from renewables. And so, what happens when the sun doesn't shine or the wind doesn't blow is all of a sudden, you know, gas is really the only power source that you can call on that can make up that difference. And so now gas has to ramp, you know, not only to hit the peak, but it's also got to ramp to be able to replace the renewables. So that's creating more volatility in the demand profile. And then LNG creates more volatility in the natural gas demand profile, because, you know, if you have a facility go down and you got 2 Bcf a day or more gas headed to that facility, and the facility can't take it, then you've got to find a place for it to go. You know, if ships decide to go somewhere else based on what's happening in the international market, then you've got to find a place for that, a home for that gas. And so, you know, the demand curve is just getting more and more volatile. So you haven't had much increase in storage capacity, despite a big increase in, you know, natural gas market overall, and then you've got more volatility in the demand curve. So we've just completed one project, storage project. It's a five Bcf project on an existing facility, so it's a brownfield storage. We have recently just approved a second 10 Bcf storage project that's on a joint venture on a joint venture pipeline that we have, and we're looking at other opportunities. So we've seen increases in our existing portfolio of storage rates, where we have market-based rates. You know, we've done one project, we've got another project underway. We're looking at other opportunities. On the greenfield side, you know, we're people are starting to have conversations, right? So greenfield hasn't been in the money, but I think as, you know, storage rates have stayed higher for longer and people continue to see more and more need for storage, I think, you know, at some point, we're going to get to the point where a greenfield storage will make sense. Everything you've said so far kind of points to just a need for additional capacity on various parts of natural gas infrastructure and beyond natural gas as well. There have been a number of regulatory developments, court rulings and such, that have impacted infrastructure projects more broadly. With the growth opportunity you see ahead of you, but coupled with this, you know, regulatory backdrop, what are your expectations on the permitting and regulatory front? How do you see this process evolving, you know, election, post-election, and beyond? Okay. So yeah, we have seen a number of different rulings, mostly positive, a few a little troubling, but I think it's gonna- it's all gonna work out. So, you know, on the positive side, there was a proposed EPA regulation, the Good Neighbor Plan, that was going to impact us on all our compressor stations. That got stayed by the U.S. Supreme Court. It's back being heard, the underlying case at the D.C. Court of Appeals. We're very happy with the Supreme Court decision. You know, a stay means that we're expected to prevail on the merits. It's likely that we will prevail on the merits. So I think at the end of the day, you know, what that does is it, you know, one, it means that we're not spending any money in the interim until we get more guidance, till we get some decisions. And two, you know, likely, it probably knocks down those expenditures and spreads them out over time. And so from, you know, from a regulatory perspective, you know, we've seen a lot more regulations in the last three to four years, and so, you know, I think that was a positive decision for us for sure. We also saw the Chevron doctrine, which, Chevron doctrine said that the court should defer to the regulatory agencies, give deference to the regulatory agencies. We saw that be overturned by the Supreme Court. I think that's good because hopefully, that tends to rein in some of the unnecessary regulation. You know, two positive things that we saw coming out of the D.C. Court of Appeals was we had two permits that had been appealed by others upheld. So our East 300 permit and then our Evangeline Pass permit were both recently upheld at the D.C. Court of Appeals, so that obviously was fantastic news for us. On the other hand, we saw some others in the industry where their permit got vacated, one on a pipeline project, the other on a combined LNG and pipe. You know, not to get into the nuances of those cases, but I think at the end of the day, what we have to do as an industry, and as the FERC, we've got to make sure that when we are going through these regulatory processes, that we are dotting all the I's and crossing all the T's. I don't think that necessarily means that those processes have to drag out a lot more. You know, we were able to do that again on East 300, on Evangeline Pass, and so I absolutely think that that is something that can be done. But you just, you can't cut any corners on those permits, and that's just gonna be incumbent on the industry. We've seen that when we do a good job, you know, the permits are upheld. Got it. Maybe turning to the liquid pipeline assets within your products segment. I'd love to touch on the pending conversion of Double H to NGL service in 2026, which should, you know, facilitate the flow of Bakken NGLs to fractionation markets in Conway and Mont Belvieu. So how does this project tie into your longer liquid strategy? And how do you think this will impact potential competitive dynamics within the Bakken and around the Powder River Basin? Sure. So we've got a lot of gathering and processing in the Bakken. We've got so really only about less than 10% of overall Kinder Morgan is gathering and processing, but we do have a decent position in the Bakken, decent position in the Haynesville, and I've talked about earlier in the Eagle Ford. In addition, coming out of the Bakken, we have had a crude line, Double H. It is somewhat disadvantaged relative to some of the other egress options in terms of where it goes. And so we're sort of playing second fiddle there. And so what we've seen in the Bakken and what we expect in the Bakken is relatively flat crude production. You know, you might see a little bit of an increase, but relatively flat crude production. But you're seeing increasing GOR. So, you know, residue gas is expected to increase. NGLs are expected to increase. We thought, you know, a better value for that for our Double H pipe was an NGL service, where the market's expected to grow. And we also, you know, the first prong of the strategy was really building residue gas export capacity. We have a project that we started prior to the Double H conversion to handle the residue gas. The second piece of the strategy was to build, you know, the NGL export. We had, you know, we signed up a contract sufficient to underwrite the conversion. We have the ability to handle more barrels there. And so as the market grows and the, you know, the way that this is all working out, we're gonna have the ability to pick up additional barrels coming out of the Powder River. So I think, you know, we've got the gathering system, we've got a residue gas egress option, and now we've got a NGL egress option. Great, and maybe now shifting to the renewable side of things. So you spent, you know, time and capital investing in the renewable fuels infrastructure as far as renewable diesel goes, as well as, the RNG assets that you have ramped up three out of the four. Can you give us an update on how all that is progressing and maybe, you know, any updated timeline on the fourth plant coming into service on the RNG side? Okay. Starting on the renewable diesel side, so the opportunity in renewable diesel, at least on the renewable diesel itself, is really on the West Coast, because that's where you get both the federal tax credit, and you can get some state tax benefits associated with renewable diesel. So we have put into service or converted eight hundred thousand barrels of regular diesel into renewable diesel of tank storage. And we're also able to ship about fifty-seven thousand barrels a day of renewable diesel, you know, on our pipes. It took a little while to ramp up, to that 57,000 bbl a day, but we're getting close at this point, so that, that capacity, is starting to be highly utilized, and we're starting to look at incremental projects, for renewable diesel on the West Coast. Now, in, on the Gulf Coast, you know, that is an area where we've been focused on the renewable diesel feedstock, and so we've invested about $150 million to build, heated, storage to handle the feedstocks and then be able to load those onto barges. And we also handle, renewable diesel feedstocks elsewhere across the portfolio, but those have been existing positions for a while. They aren't as recent as the, as the Gulf Coast expansions. So that's, you know, that's what's going on in renewable diesel, potential to expand a little bit more in California. On the RNG side, you know, we made about $1 billion of acquisitions. And as part of those acquisitions, we are converting some of the landfills to handle RNG that's for the transportation market. And we've built facilities to be able to clean up that gas. And as you know, they've been slow to come on. We've had some challenges bringing those on. So I think it's a more difficult business, I think, than what we originally anticipated. We've got three of the facilities that are complete. You know, two of those facilities ran really well in August. The other one ran pretty well. You know, it had a rough start to August, but now we've gotten it up and running better, and then the fourth facility, I think, you know, comes on at the end of the year, but you know, once you can get those things up and running consistently, you know, I think we'll be in good shape, and I think two are doing that now. One's on its way, and then we'll bring the fourth one online in the fourth quarter. Very good, and finally, I'd love to get your sense or update on the capital allocation priorities from here, so can you tell us about, you know, a, what you see as steady-state run rate CapEx for the organization, and how do you plan to balance that growth and/or inorganic growth versus maintaining comfortable leverage and returning cash to shareholders? Okay, so, you know, if you look at our free cash flow, you know, there's really two big uses of our free cash flow. One is obviously for the dividend, and then the second is for our expansion capital program. Our expansion capital program, we expect to be around $2 billion. I mean, that could be $2 billion, that could be $2.1 billion, that could be $2.4 billion. I mean, just in that range. It's hard to project exactly what it's gonna be every year until we get there, but in that range, so, you know, depending on exactly what it is, there may be a little bit of cash flow left over. With the cash flow that's left over, you know, we can do opportunistic share repurchase or we can pay down debt, right? To the extent that, you know, we don't feel like that the right returns are there on the opportunistic share repurchase, pay down debt, and wait for the right opportunity, to redeploy that capital at a later date. The other thing that's gonna happen over time is, as a result of the projects that we're bringing online, you know, and the EBITDA coming from those, you know, leverage should drift lower, right, over time. Right now, we're running in and around four times, but that will drift lower. That creates capacity on the balance sheet for, you know, obviously, further share repurchase, opportunistic share repurchase. But I think at the end of the day, you know, where we wanna keep the balance sheet is between 3.5x and 4.5x. You know, if there's a ton of opportunity out there, we may take it up a little bit. When we see less opportunity, that'll move back down and create capacity, but always, you know, intending to stay within that range. Wonderful. Well, thank you so much for the time and all the insight. All right. Thank you very much.