Kinder Morgan, Inc. ($KMI)

Good morning, and welcome to the second session of the first morning of the 42nd Annual Strategic Decisions Conference. I am Bob Brackett, Co-Head of Energy and Transition here at Bernstein. We are not expecting a fire drill. And so if the alarms ring, please take that seriously. The primary exit, will [ be ] straight out in the back door, down the right to the escalator area down to the street level and out. If for any reason, that path is blocked, you'll go straight to one of the internal stairwells right outside the door, go down and follow the lighted signs there. This is your conversation scattered across the room or little blue cards with QR codes. Those QR codes will take you to the [ pigeon ] hole app, type your questions, and those will get delivered up to the front of the room. And from there, I can ask them. While I wait for your questions to come in, I'll start my conversation with Kim very much as a pyramid. We'll start with talking about macro issues. We'll move down into strategic issues, financial issues, and sort of specific assets, operations, projects, et cetera. So that's how the conversation will proceed. With that, I will sit in 1 second. But first, let me thank Kim for joining us, Kimberly Dang, the Chief Executive Officer of Kinder Morgan.

Thanks, Bob.

So we're going to start with macro and you all do much more natural gas than most anybody and more natural gas than anything else. And on the gas macro, we'll start with volume, which we both like. And then we'll talk about price, where onboard [ and ] perhaps engaged requiring it than you are. If we think about gas demand growth in the U.S., we talk about your numbers, something like '26, '27 Bcf of growth to 2030. To put that into context, the oil demand globally is likely to rise less than 1 million barrels a day each year to 2030. If we take something like divide by 6 and take 27 Bcf, that's 4 million barrels of oil equivalent growth just in the U.S., just for gas in the next 4 years. It's more than global oil demand growth. How do you get there? You do your own work on that? Why are you above consensus, if we call WoodMac consensus on those volumes?

Yes. So you're right, our number is 26 Bcf a day. [ Going ] from 115 Bcf a day market in 2025 to [ 141 ], 2030, driven largely LNG is the biggest driver. It's about 18 Bcf of that. Power is the next biggest driver. It's about 5. And then you have exports to Mexico and industrial, et cetera, that balance out the rest. The biggest places, we're higher than WoodMac, which is at [ '19 ] on both LNG and power. And I think that we will, at some point, update our external forecast. And I think, quite frankly, I see the 2030 number getting higher, likely based on everything that's going on around power and maybe a little bit on LNG. And I think that what's happening in the Middle East and the Strait of Hormuz, long term is good for the United States in terms of being able to be a supplier for the global markets and being able to be looked at as a reliable supplier. And so I think that is also potentially incremental demand driver from what's in -- what's in our numbers today. And so I think that creates a great backdrop for us where we've got 2/3 of our business is natural gas. We've got 58,000 miles of gas pipelines. We've got a $10 billion expansion -- approved expansion project backlog where almost all of that is associated with gas. So I think there's a $10 billion opportunity set on top of the $10 billion of approved projects that we're working on. And so I think it just puts us in a fantastic position.

And arguably out to 2030, big driver of growth around LNG, big around power demand, data centers and other things, [ is ] fairly locked in. We're sitting here mid-2026. We probably won't be surprised. Everything that's cutting steel today on the LNG side will be there. Pretty hard to come up with a new project -- and then beyond, you just have it continuing to grow on both of those drivers into the mid-2030s.

Yes. I mean we haven't done our number -- updated our numbers to the mid-2030s yet. But we'll be turning to that in the next 6 months or so to get into 2031, 2032. But yes, I think that there's the potential for more LNG, and I think there's the potential for more power. And I think as Mexico's gas demand continues to increase and their domestic supply continues to decline, there's potential for more exports to Mexico as well.

And for each molecule of demand, there has to be a molecule of supply [ how ] the physics work. How do you think about that? And we'll spend a lot of time in the Permian right? And so where does -- have you thought about where all that gas comes from?

Yes. So when you think about -- I think there's three primary basins. It's going to be the Permian. It's going to be the Haynesville and it's going to be the Marcellus-Utica. I think the constraint on the Marcellus-Utica growth is really [ pulling ] capacity out. From a dry gas perspective, it is the most competitive supply out there but it is expensive to get it where you need it, which is on -- primarily on the U.S. Gulf Coast. And then I think the Haynesville -- Haynesville is a higher cost to produce, but it's born in the right place, right? It's right there by all the LNG supply and by a lot of where the power demand will come across the Southern United States. So -- and then the Permian is just a byproduct, right? And so -- and there seems to be a fair amount of gas waiting on capacity out there. And so I mean, there's -- we've got a pipeline project, 570 a day that's coming on in the second quarter. And then there are two more projects coming on in the third and the fourth quarter, and that should bring some incremental supply to the market.

And if you put that in context, that 26 [ Bs ] of growth, that's like two more Haynesville. It's sort of another Permian. It's a huge jump to where we are already in Appalachia or it's some blend, but it's a significant number. Talk to the Permian then. We watch negative prices in the Permian. They're sort of a build fill, build fill cycle. You've got [ GCX ] expansion coming will there be a day -- do you expect those lines to fill quickly?

I do. I think they will fill very quickly. And -- but -- the other thing is, as you look -- those lines all come on this year. If you look at the spreads in '27 and '28, I mean they're still wider than the cost of transport. So they're well over $1 in '27 and '28 to move that gas out of the Permian. So that would support the premise that there is pent-up gas that is waiting on pipeline capacity. And I've heard numbers anywhere from 1.5 to 2.5 Bcf.

And then if we talk about connecting that demand or that supply to demand, I know where all the LNG terminals are going to be [ the ] great state of Texas, the great state of Louisiana, I'll bet against almost any other coastline for any other state. Power demand, which is that other driver has a choice, and so that power demand could be in places that you can connect to on the supply. It could be in places where you don't really need to move that gas. You could drop the data center into the Permian. How do you think about the location of future power demand growth for gas?

Yes. I think a couple of things on power demand. With respect to AI specifically, I think the Texas market is going to be the leader in terms of data center supply added. And I think closely behind that is Georgia, Virginia is the other state that's got big. So, I mean the Texas market is a fantastic market for us because you've got the Permian and -- but [ he's ] also got Eagle [ Ford ] supply, and you've also got now what we call the Western Haynesville, which is also in Texas. And then you've got huge amounts of demand coming from export LNG is coming from the data center development. It's coming from population growth and needing more power to serve the population. And it's coming from backing up the huge renewables that the Texas has built. So there is a huge demand for power growth in general in the state of Texas. We have seen data centers, you see some that are building relatively close to what I'll call major [ metropolitan ] areas. They're not going to be too close because those things require tremendous amounts of land. A lot of times, they're building the data center and putting the power plant next to it and so they need a tremendous amount of land. We've seen them locate, as I said, next major [ metropolitan ]. We've seen some want to locate out in the Permian Basin. But even those that are locating out in the Permian Basin, we're seeing there's the potential for projects there because they're not -- you can't go locate in a field where you've got all these wells drilled, right? You've got to be somewhere outside of that. And most of our pipelines out there are full. And so there's the potential for projects out there as well. And you've got -- we've got -- we've seen coal conversions in the Texas Panhandle. That's driving power demand. So I mean, I think our probably largest footprint is in the Texas market, and the Texas market has one of the best growth profiles I think, for natural gas.

You mentioned population growth. You mentioned the East Coast. You mentioned the South Coast. You left off one of the coasts. Is there an opportunity where there's population growth and data center growth as we move west of Texas?

Yes. I think there is currently a proposed project that's contracted that is expected to be built to the west by another firm. And that should serve a lot of the demand with respect to data centers in Phoenix and the power plants in Phoenix. But I think there may also be opportunities around the West Coast of Mexico, around export LNG and maybe some incremental power as well. So I don't think it's near term, but I think longer term, there may be some incremental opportunity out there.

And maybe talk about -- we're going to end up talking about your $10 billion of projects, line of [ sight ] . There's another $10 billion you've talked about. How do you engage with your customers on the demand? So I understand how you engage with your customers on the supply side. Talk about what do you have to do to engage with future customers on the demand side? How long do those conversations take?

Some are quicker than others. So it's -- look, we've got a great demand picture and then we've got a great asset base. And so when you marry those two things up, I mean, there are a lot of people that are coming our way in terms of customer conversations about potential supply. And so I think the quickest projects are ones where it doesn't require much expansion capital, maybe you're building a small lateral and it's for one customer. It's just easier one-on-one to get something done. The ones that take longer are the bigger projects. So where you need multiple customers to support a project and they all have different deadlines. And so those take a little bit longer. So -- but we like them all, right? We like the singles and the doubles, they come with less risk. A lot of times, they're probably better returns. The [ greenfield ] projects. They come with a little bit more risk. A lot of times, they're more competitive. But they -- at the end of the day, they're a lot larger and deliver a lot more meaningful bang to the bottom line. So we've got all sorts of different projects in the backlog. The three largest projects in our backlog are total about $5.3 billion, so about 50% of [ it ] and so those are the large ones. And then obviously, the other half is smaller sized projects.

And we've talked about volume of demand volume of supply price, price matters a lot for my E&P coverage, especially my levered E&P coverage. Dollar move in gas for me makes me look like a fool or a genius [ the ] left side of that right now. $15 move in oil, which is what we've seen in the last week, amidst a backdrop of a potential Strait of Hormuz deal, right? Both of those units move your revenue, your EBITDA a few percent, 1%. So do you care about oil and gas prices? And then if you do or you don't, where are they going?

Yes. Okay. All right. I'd say yes and no. So in the short term, we are pretty insulated from any commodity price moves. As 65% of our business is take-or-pay contracts, meaning people have to pay for the service, whether they use it or not. 26% of our business is fee-based, meaning there is no variation in the price. You could have some variation in the volume, but no variation in the price. We've got another 5% that's hedged, that has commodity exposure but hedged and generally and then we've got 4% that's unhedged. So relatively modest exposure based on the way that we contract with our customers. That being said, what impacts our customers impacts us. And so in the long term, we do care about where commodity prices are. In the short term, it's not so important. When we think about long-term commodity prices, though, I think there's a broad range from our perspective that is pretty acceptable. And the reason is that it's at the extremes where we see demand or supply getting impacted and really long-term demand and supply getting impacted. And that's what impacts people's willingness to sign up for capacity. So if you see -- if we saw gas prices at $8, that would probably negatively impact demand, which would not be good. If you see prices at $1, you're probably going to negatively impact supply, which would not be good. So we don't -- we prefer not to see the extremes in our business. I think though, when you look at the situation in the United States, we've got plentiful supply for the foreseeable future. And I think you've got a strong demand signal coming from power and LNG. And so I think it's unlikely on a sustained long-term basis that you see really high prices which I think is -- that is really good for our business. And then I think you have seen the E&Ps be more disciplined in their investments. And they've also gotten more flexible in terms of their ability to manage those wells and turn them on and off as they see what I'll call a shorter-term pricing. And so that also helps, I think, mitigate really strong downside risk. We'll continue to see volatility in this market, that can be caused by extreme demand and weather, [ that ] can be caused by supply constraints. So I'm not saying we won't see a lot of volatility, but I do think that prices will remain in somewhat of a reasonable range that will be supportive of our business.

Part of your business is refined products, and we'll talk to that later. We have a question around tank bottoms. And what are you seeing in the U.S. around inventories for refined products. How long can the Strait of Hormuz continue before there are physical disruptions?

Yes. So it's our customers' product, and so I can't exactly comment on that. But I would say, we are moving tremendous. One of the outcomes of this is we are moving tremendous amounts of petroleum products across our docks in Houston. So we have a -- we've got [ roughly ] over 40 million barrels of clean product storage in the Houston Ship Channel. And we've got four ship docks. We've got barge docks. And so we are seeing a large amount of product move as a result of what's happening. And I think long term, that is really good for the United States that we can potentially, again, be the reliable supplier for more of the world's market. I think to the extent that you get any decline in motor fuels, although we're not seeing that right now. Then you can export -- we've got the most efficient refining capacity, I think, almost in the world here. And a lot of that's being fed into our -- in our terminals in Pasadena and [ Galena ] Park. And so it's presenting -- it's a great opportunity for our customers to take advantage of.

It's not clear if we're -- we're not at the beginning of the crisis on Strait of Hormuz and maybe closer to the end than the middle. If we stayed in the middle, people worried that you would have limitations, right, just physical limitations, and that gets solved one of two ways, either with a price signal, which we're clearly not getting [ right ] much higher price or you get it through policy levers. We've seen one policy lever, and I'm going to ask about that, [ then ] I'm just more broadly talk about what policymakers should do. Talk about Jones Act tankers. And how you think about that as a policy and how you've used that within your portfolio?

Yes. So we have 16 Jones Act tankers. For those of you who aren't familiar with the Jones Act, they have to be -- [ there ] to move from U.S. port to U.S. port, [ it ] used to be U.S. made, U.S. manned vessel and so it -- and the idea behind the Jones Act originally, and I think still has a lot of important rationale for us today is that you want to be able to maintain shipbuilding capacity in the U.S. You don't want to be entirely dependent on the foreign market to be able to build ships. And then secondly, I think from a national security perspective, it's an important policy as well. It's been in effect since the early 1900s. And I think there's bipartisan support for it in Congress and for good reason. We've seen a temporary waiver [ of ] Jones Act ships tend to have higher day rates than the international shipping market. Although early in this crisis, the international rates sort of above the Jones Act rates. Now I think they've come back down below the [ genset ] act rates, but they tend to be a little bit more expensive because of the U.S. crews and the U.S. made, et cetera. So our contracts on those with our customers are over 3 years. on average. We don't really have anything significant -- has significant that's coming up. I view the waiver as a temporary effort to try to address supply -- and I think on a long-term basis, there's good rationale and good support for the [ Gentex ].

[ Do ] you keep the Jones Act to keep the ability, right, FDR, forget which President, but the idea is you want a homegrown Navy and you want a home grown ability of sale, right? So having merchant marines that can feed a potential Navy in the future is probably a good thing. So it sounds like temporary waiver makes sense permanent doesn't, if you're thinking longer term?

I think that's right.

One would think, given the role of the Navy [ in ] Strait of Hormuz, abandoning the Jones Act doesn't feel like a long-term...

I agree with that. And the temporary waiver has had no impact on us.

What else could, should and should not policymakers do given today's disruptions?

Well, from our perspective, what we think is really important would be some type of permitting reform. And I think that would give more durability and more stability in terms of building the needed infrastructure across the United States in the long term. I think right now, the environment is great, [ but ] environments can change as administrations change. And so I think that if we had a more long-term durability in those policies, that would be good. Things like making the standards for courts to overturn certificates, a higher standard. Maybe it had to be -- the issuance had to be arbitrary and capricious. Making it more difficult, I think, for states to get in the way of projects, I think, would be good. I think if you look, the Northeast could desperately use more gas. And it is -- there's very close supply to the Northeast that is easily easy to get here but some of the state policies haven't allowed that. So when you get to the winter, the Northeast is running fuel oil importing importing a lot of LNG and so the margin price on gas is the world market for the Northeast. So I think if you could help alleviate some of the state bottlenecks, that could be very good as well.

Yes. [ Touching ] on that a bit. If we could bring Northeast New York -- sorry, Northeast Pennsylvania gas across New York into New England, that's interesting. There is a strong seasonality to New England.

Yes.

There's the permitting issues. But if you -- if the permitting was fixed, does the economics work to run a pipe to New England when there's such seasonal demand tariffs work for everybody?

I mean they would have to sign up. Either they would have to sign up for your own capacity or you would have to -- the seasonal service would have to come at an extreme premium to make it work. I mean, when we tried to build into the Northeast back 2015-ish, the problem wasn't only permitting. Part of the problem was with respect to the independent power producers. They really -- it couldn't sign up for some of the capacity because it was -- they couldn't get the capacity charges reimbursed. They couldn't recoup those, which made it which made it uneconomic for them. So -- and that hasn't really particularly changed. So I mean the Northeast market is a difficult one to solve.

If we talk about your strategy, 2/3 gas focused, a big chunk refined product, carbon capture a carbon business, and we have a question on that. It would be great if you can touch on your upstream assets, CO2 flood in the Permian Basin. Is that a very economical side project in [ pots ] or does this provide a window into Kinder Morgan's future plans?

Okay. Let me talk a little bit about the background of how we got into this business, which I think is important. So we had a sales and transport business. So we were -- we were producing CO2 in Southwest Colorado. We are transporting it by pipe to customers who are using it to get oil out of the ground in tertiary recovery. And what we found was a lot of people didn't know how to do that. And so we developed an expertise over time, all the reservoir engineers, et cetera, to help them get that out of the ground. And so we thought, well, hey, if we can do this on an opportunistic basis, meaning we can buy some of these fields on a good return on just a rundown basis and then get in there and if we get a CO2 flood, and that CO2 flood successful, we can really blow things away, "Hey, wouldn't this be a good business." And that business, we require -- and so we did. And we have two significant fields, [ SACROC ] and [ Yates ]. This overall, just to put in perspective, the oil and gas production business is 4% of our overall business. So it's not it's not a large part. And then the sales in transport of CO2 is like 2%. So overall, it's not an overly significant -- we require higher returns on that business to pursue investments there. So on a risk-adjusted basis, I think we get good returns in that business, and we have an expertise that I think is pretty serious in the market. There aren't a lot of other people who know how to do this. I think two things that, that positions us well for the future. One is to the extent that you can ever do CO2 flooding in some of these fracked fields and get more oil out that way, that would be a tremendous opportunity. I mean there's studies being done on that at this point in time. So unclear if and where that will be a potential. But if it is, it could be significant. And then the second is we understand how to put CO2 in the ground, and we understand how to keep it there. And so CO2 sequestration conversations have slowed way, way down in the last 1.5 years, 2 years. But to the extent that ever picks up again, that would be an opportunity for us as well.

You all know how CO2 moves through the Permian better than anybody, that unconventional opportunity and you've chosen high-quality ports, reservoirs with a lot of oil in place. And so you've picked the better pieces. Is there an unconventional CO2 flood? Is that something you spend time on? Or do you want maybe the E&Ps to go do the work there and then you can come to...

Right now, I would say we are mostly watching the pilot projects that some others are doing.

And then if we back up one level of strategy, I've often said people in the [ room ] strategy to me is what you won't do as opposed to what you will do I'll ask you that question, and I'll put it in the frame of international expansion, for example. What won't Kinder Morgan do?

So we have looked internationally a number of different times. And I think most significantly in Mexico, we also invested heavily in Canada over 2005 to 2015 period. And ultimately got out of Canada, found that it was hard to get infrastructure and especially regulated infrastructure built in that market. And so we sold out of that market. In Mexico, we found it difficult to get returns that compensate us for the risk. And generally, that's what we found in other international markets as well. So I wouldn't say it's off the table. I think if we can find the right returns [ to ] the opportunity set that's big enough, I mean, I don't think you go do one project, but if you can find an opportunity that was big enough at the right returns. That takes into account some of the incremental risk that you face, for example, currency when you go to the international market, then it's not totally off the table. We just haven't found that today. Another thing that we have not done, which is more -- which is an adjacent business is the power development business behind the meter power. I think we've got tons of opportunity on our existing asset base. And I think generally, new businesses are hard, at least the first few years of them. And so I don't -- it doesn't make sense to divert a focus at this point in time. So I think what I think -- when I think about our growth, we're sticking to our knitting. We're doing what we know how to do. And so I think we have high-quality growth for our investors.

That growth comes from $10 billion backlog. And you could -- another $10 billion, I don't know what you call, it's not quite a backlog. Of the $10 billion backlog, 60% is power demand?

Power demand, [ 20% ] is LNG.

And what's the other 20%?

The other 20%, well, some of it is not natural gas. So there's about 12%, well, that's gathering and processing on the gas side and CO2. And then you've got a little bit of some of the other business products and terminals. And then it could be exports to Mexico. It could be industrial demand, other things on the natural gas side.

And of the $10 billion back backlog, what -- can you share a little flavor there? I don't know that you're going to give percentages or projects, but is it power demand heavy or comparable ratios?

I think it's power demand heavy is what I would say. And the reason we don't share a lot on the opportunities, the $10 billion opportunity set is it's a competitive market. And so we've got to go out there and compete against a lot of other pipeline companies and others for business. And so we want to make sure that we're not compromising our competitive position. But I would say, in general, it's kind of more of the same. Power heavy, a little bit of LNG and potentially the West Coast, potentially West Coast on the products pipeline side.

Is it a similar scale of singles, doubles, triples and home runs, right? You talked about half...

It is diverse in terms of that. So you've got singles and doubles, and then you've got a few out there that are really big. And so it's a combination. I'd say largely heavily focused across the Southern United States, just like the existing portfolio of approved projects is.

And if I think about ...

Largely natural gas.

Largely. If I think about monetizing that $10 billion backlog, think about roughly $1 billion a year of maintenance CapEx for you all, $2.5 million to $3 million of dividend and you're comfortable spending about [ 3% ] a year of CapEx to sort of move that backlog through the system. Is that the right math? Is $3 billion the right number? How do you get there?

I think $3 billion is the number that we can finance out of cash flow. So when you start looking at cash flow that's coming from our assets, after you pay the dividend, after you pay sustaining, there's, give or take, $3 billion. Now that $3 billion, I expect it to go up over time for a couple of reasons. One, you're going to get more EBITDA as projects come on. And two, your debt-to-EBITDA is going to continue to come down over time. And so that's going to create more balance sheet capacity. Right now, we do have excess [ ball ] sheet capacity. And so if we have expenditures over $3 billion a year, we can easily accommodate that. So the target range on our balance sheet is 3.5 to 4.5x. Right now, we are sitting at 3.6x. So at the low end of the range, we expect to end the year about 3.7x because we did a $500 million acquisition. We don't get all the earnings this year. So that will push it up a little until we get a full year of earnings. But every 0.1 turn on the balance sheet is worth 200 million of capital. And so you can spend significant capital on top of the $3 billion that we can spend just from cash flow that we produce.

And then [ they ] further down the line, JVs or partnerships would be another sort of...

Our view is that there is unlimited capital for good risk-adjusted return projects. And so where we target to do our projects, I think if we needed to go get external financing to supplement our own internal financing, I don't see an issue with that at all.

And so then when you get these projects across your desk or across the board room on the table, what are the yardsticks? You've got the 6x CapEx to EBITDA ratios. You've got different projects of different scales. But ultimately, how do you allocate that capital? What project gets the green flags?

So a couple of things. One is when we're looking at it internally, we're looking at really the life of the project. So we're looking at an IRR, not not a year 1 EBITDA multiple. The year 1 EBITDA multiple is more to facilitate for investors sort of the cash flow that we expect to come off of the EBITDA we expect to come off of these projects. So we're looking at a 20, 30-year cash flow time horizon and the return that these projects generate. In terms of the $10 billion backlog with the exception of the 12% that I said is in gathering and processing and CO2, all those projects are already approved. And so really, we're talking about the incremental projects. The way we think about it internally is all of our business units know where the return hurdles are. And they vary. For example, CO2 has a higher return hurdle than a natural gas project. A [ natural ] gas project does and gathering and processing natural gas has a higher IRR target than transport project that's backed by a 20-year contract with the utility. So people generally know where those return hurdles are. And then we tell people, if you're close or there's something unusual about this project or go ahead and bring it in and let's talk about it. And so we're talking about anything that's even close to our return hurdles. And then at this point, we hadn't had to [ ration ] at any capital. So if they're hitting the return hurdles and we're getting the right credit and then I think those projects are getting approved.

Any organizational capacity limits, where do you have an organization that can spend $3 billion, $4 billion, $5 billion?

I would say, right now, when you look at the $10 billion backlog, we are in really good shape. In terms of getting those projects built in terms of project management and operation staff you hire as you bring those on. But I think from a project management standpoint and execution of those projects, we're in good shape because we're prepared for that. I think if you added significantly to that, then we would probably have to look at adding resources. But what I would say also is that generally, you enter into a project and then especially on the regulated side, there's a number of years to get your permit and -- largely or at this point will probably come towards the tail end. Right now, the existing project backlog has an average in-service date of the first quarter of 2028. So if you think about we're in mid-'26 and you need a couple of years on those big projects, that will start pushed towards the tail end of the term.

And then process, filters, appetite for M&A and then dispositions, how do you keep the pruning?

So everything competes for capital, right? And so I think we just did a recent acquisition, $500 million, not overly sizable, but a single is what I'd say. And so it competes for capital the same way the expansions do I think that when you look at those acquisitions, they come with in-place cash flow, so you're getting cash flow earlier. You don't have the same build risk with those but it also comes with a few unknowns. So they -- on a risk-adjusted basis, they compete with the expansions as does share repurchase. And as we said, we don't have any programmatic share repurchase. Our share repurchases is opportunistic.

Some questions are coming in. One is we can't have a session while [ talking ] about turbines. With materials, turbines, compression lead times, et cetera, so far out, what type of time line are you operating on for new projects and maybe more broadly, what are some of the constraints you would worry about?

Sure. So we have lots and lots of discussion with our vendors on this. And so right now, historically, what you've seen is the long pole in the tent has been on big projects. So let me talk about the big projects, the [ par ] Seven Seas. The long pole in the tent has been the [ FERC ] 7C application. But with this administration, they have moved back brought in the time to get a permit. And so with that, you start getting closer to the procurement to the time lines for [ procurement ] but we're not quite there yet, okay? So with a little bit more permitting improvement, then what you'll see is procurement could become the longer pole in the tent. But we are -- the way we handle it is as soon as we approve a project, we ordered the pipe and we order the compressors for the pipeline. And we've been in discussions with our vendors about that for months in advance of that.

The day that government permitting is faster than the supply chain. I don't know is that a good thing or [ about ]

Yes. And the other thing is a lot of the suppliers are adding capacity. Now it's not available right away. But in a couple of years, we should be in a better place.

And a follow-up on CO2. You're one of the few companies who has created an actual end use for CO2. Are there other sectors CO2 can be economically viable as an actual product besides green initiatives?

Not -- in our -- in the midstream space, not that I am aware of.

And then a question. You all are very careful with capital and returns that move the needle. The question about the small projects pop out? Or do small projects compete for the same returns as large projects?

It depends on the risk profile. So obviously, larger projects, you're going over long stretches of land. That comes with a certain risk. Smaller projects or typically, you've got a shorter build, right? So that -- it may have less risk from that perspective. It's all -- but you have to look at the counterparty credit. When you're doing the longer builds, you may have a utility credit, you're doing shorter build, you may have somebody that doesn't have as good a credit. So all those factors go into the return and to the credit that we require as we go through and approve these projects. But I wouldn't say that we have a bias towards a bigger or smaller. The bias is about the risk and the return.

On the upstream side, sometimes you can do the large anchor project live with a [ $12 billion ] to $15 billion return all of the tiebacks or super high returns -- so I don't have [ that ] in analogy works.

So that analogy works in terms of we still have to have a reasonable return on the big project, but would we accept at the lower end of our return threshold because this project has all sorts of potential offshoots, Absolutely. And that is something that we frequently consider. I think we need to get to a certain minimum level of return on the anchor project, but -- and -- but yes, I mean, we see that all the time where we build a project and we get a lot more benefits than what we expected in our initial underwriting.

And then on the project portfolio, we talked a little bit about GCX expansion. What should investors watch for in terms of delivering projects over the next 12 months?

Delivering projects. We've got a schedule of the projects that deliver over the next 12 months. Let me just talk about the big projects that we're working on. So if you look at those three, [ Trident ], which is moving around Houston to the southeast side for LNG and a little bit of power. That project, we are under construction today. And that project delivers in the first quarter of 2027. Now that project has multiple phases. So it stages in over '27 in 2028. We're expecting our [ FERC ] certificate this summer. And then that comes in, in mid-2028. And then South System 4 comes in at the end of '28 and in '29. It also has 2 phases. And as I said, most -- our average in-service date is the first quarter of 2028 on the entire $10 billion. So we've got a lot of growth coming over the next few years. I think '27, probably less of it than '28 and '29 have more of the growth that comes from the backlog.

And then in our last 2 minutes, ultimately, what's the value proposition for investors in the room beyond owning your stock?

Yes. I mean the -- it's an attractive dividend and nice growth. And the dividend is about 3.5% right now. We have been growing that dividend modestly. Dividend is well covered. It's about a 40% payout on cash flow from operations. We cover it by about 2.5x. And -- it's underpinned by 65% take-or-pay contracts, 26% fee-based business. We got a very strong balance sheet. BB rated BBB+ rated equivalent across the board at the low end of our leverage range. So very stable cash flow base to support that dividend. And tremendous growth, high-quality growth in the -- with a -- largely take-or-pay contracts in a business that we know well, on the $10 billion approved backlog and the potential for more to come.

Fantastic. Thank you, Kim. Thank you, audience. I look forward to seeing you in further sessions.