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 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 are little blue cards with QR codes. Those QR codes will take you to the Pigeonhole 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 one 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 I'm more 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, you know, the oil demand globally is likely to rise less than a million barrels a day each year to 2030. If we take something like divide by six and take 27 BCF, that's 4 million barrels of oil equivalent growth just in the U.S. just for gas in the next four 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 Wood Mack consensus, on those volumes?
So you're right. Our number is 26 BCF a day, going from 115 BCF a day market in 2025 to 141 2030. you know driven largely LNG is the biggest driver it's about 18 BCF of that you know power is the next biggest driver it's about five and then you have exports to Mexico and industrial etc that that you know balance out the rest you know the biggest places we're higher than Wood Mac which is at 19 on both lng and power um and you know i think that you know we will at some point update our external forecast and i think quite frankly i see the 2030 number getting higher likely um based on everything that that's going on um you know around power um and and maybe a little bit on lng you know and i think that the you know what's happening um in the middle east and the Strait of Hormuz, you know, 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, you know, that is also potentially incremental demand driver, you know, from what's in our numbers today. And so, you know, I think that creates a great backdrop for us where we've got you know two-thirds of our business is natural gas we've got 58,000 miles of gas pipelines we've got a 10 billion dollar expansion approved expansion project backlog where you know almost all of that is associated with gas so I think there's you know a 10 billion dollar opportunity set on top of the 10 billion of approved projects that that we're working on and so you know I 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. LNG's 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. It'd be pretty hard to come up with a new project. And then beyond, do you just have it continuing to grow on both of those drivers into the mid-2030s?
Yeah, I mean, we haven't updated our numbers to the mid-2030s yet. But we'll be turning to that in the next six months or so to get into 2031, 2032. But, yeah, 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, right? That's kind of how the physics work. How do you think about that? And we'll spend a lot of time in the Permian, right? And so have you thought about where all that gas comes from?
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 pipeline capacity out. You know, 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 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 you know a lot of where the power demand will come across this you know the southern United States so and then you know 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, you know, 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 context, that 26 Bs of growth, that's like two more Haynesvilles. It's sort of another Permian, you know. 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. There's 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. You know, and, but, you know, 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 a dollar in 27 and 28 to move that gas out of the Permian. And so, you know, 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 if we talk about connecting that demand or that supply to demand, I know where all the LNG terminals are going to be. It's 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?
Yeah, I think a couple of things on power demand. With respect to AI specifically, you know, 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, but you've also got Eagleford 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. It's 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 Texas has built. So there is 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. You know, 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. And we've seen them locate, as I said, next to 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, you know, 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, you know, 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 seen coal conversions in the Texas panhandle that's driving power demand so I mean I think our probably you know 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?
Yeah, 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, you know, 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 a lot, we're going to end up talking about your $10 billion of projects line of sight. Billion. There's another $10 billion you've talked about. how do you engage with your customers on the demand side? 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, you know, there are a lot of people that are coming our way in terms of customer conversations about, you know, about potential supply. And so, you know, I think that 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. You know, 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. 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 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 you know the three largest projects in our backlog are total about 5.3 billion dollars 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, right? 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 on the left side of that right now. Now, a $15 move in oil, which is what we've seen in the last week amidst a backdrop of a potential Strait of Hormuz deal, both of those units move your revenue, your EBITDA, a few percent, one percent. So do you care about oil and gas prices? And then if you do or you don't, where are they going?
I'd say yes and no. So, you know, in the short term, we are pretty insulated from any commodity price moves. You know, 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, you know, 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 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 that we contract with our customers that being said what impacts our customers impacts us and so in the long term you know 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, you know, 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, you know, we prefer not to see the extremes in our business. I think, though, when you look at the situation in the United States, you know, 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 know you have seen the EMPs 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 shorter-term pricing. And so, you know, that also helps, I think, mitigate, you know, 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?
So it's our customer's product, and so I can't exactly comment on that, but I would say we are moving tremendous, you know, one of the outcomes of this is we are moving tremendous amounts of petroleum products across our docks in Houston. So we have a, you know, we've got rough over 40 million barrels of clean product storage in the Houston Ship Channel, and, you know, 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, you know, long term, that is really good for the United States that we can, you know, potentially again be the reliable supplier um for more of of the world's market um i think to the extent that you get any decline in uh in motor fuels although we're not seeing you know that right now um you know then you can export we've got the 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 you know it's 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 in the Strait of Hormuz and maybe we're closer to the end of the middle. If we stayed in the middle people worried that you would have limitations right of just physical limitations and that gets solved one of two ways, either with a price signal, which we're clearly not getting, much higher price, or you get it through policy levers. We've seen one policy lever, and I'm going to ask about that, but then I'm just more broadly talk about what policy makers 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.
Yeah. So we have 16 Jones Act tankers. For those of you who aren't familiar with the Jones Act, they have to be, you know, to move from U.S. port to U.S. port, you need to be, it used to be U.S. made, U.S. manned vessel. 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, you know 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 in Congress and for good reason we've seen a temporary waiver of it Jones Act ships tend to have higher day rates than the international shipping market although early in this crisis the international rates soared above the Jones Act rates. Now, I think they've come back down below the Jones 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 three years on average. We don't really have anything that's significant that's that's coming up you know I view the the waiver as a temporary effort to try to address supply and and I think on a long-term basis there's good rationale and good support for
the Jones Act. So you keep the Jones Act to to keep the ability right FDR I forget which president but the idea is you want a homegrown navy and you want a homegrown ability of sailor right so 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 the Strait of Hormuz, abandoning the Jones Act doesn't feel like a long-term good answer.
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, you know, right now the environment is great, but environments can change as administrations change. And so I think that, you know, if we had more long-term durability in those policies, that would be good. Things like making the standards for courts to overturn certificates a higher standard. You know, 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. You know, I think if you look, the Northeast could desperately use more gas, and, you know, 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, importing a lot of LNG, and so the marginal 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.
Yeah, I'm touching on that a bit. If we could bring northeast Pennsylvania gas across New York into New England, that's interesting. There is a strong seasonality to New England. There's the permitting issues, but if the permitting was fixed, does the economics work to run a pipe to New England when there's such seasonal demand? Would the tariffs work for everybody?
I mean, they would have to sign up for year-round capacity, or 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. You know, they really couldn't sign up for some of the capacity because they couldn't get the capacity charges reimbursed. They couldn't recoup those, which made it uneconomic for them. 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, two-thirds gas-focused, big chunk refined product. carbon capture a carbon business and we have a question on that 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 quotes 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 is important so you know we had a sales and transport business. So we were producing CO2 in southwest Colorado. We were transporting it by pipe to customers who were 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, you know, all the reservoir engineers, et cetera, to help them get that out it at the ground. And so we thought, well, hey, you know, 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, you know, wouldn't this be a good business? And that business, you know, we require 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 a large part, and then the sales and transport of CO2 is like 2%. So overall, it's not 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, you know, is pretty scarce in the market. There aren't a lot of other people who know how to do this. I think, you know, two things that that positions us well for for the future. One is to the extent that you can ever do CO2 flooding in some of these fracked fields, you know, 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, you know, if and where that will be a potential, but if it is, it could be significant. And then the second is, you know, 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 year and a half, two 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, porous 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 in as a fast follower? 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 to people in the room, I'm like, no, 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 and an opportunity set that's big enough I mean I don't think you go do one project but if you can find you know an opportunity set that was big enough at the right returns that takes into fact into account some of the incremental risk that you face for example currency when you go to the international market then it's not it's not totally off the table we just haven't found that today you know another thing that we have not done which is more which is an adjacent business is the power development business behind the meter power you know i think we've got tons of opportunity on our existing asset base and i think you know generally new businesses are hard at least the first few years of them, and so it doesn't make sense to divert our focus at this point in time. So 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. Another $10 billion. I don't know what you call it. It's not quite a backlog. Of the $10 billion backlog, 60% is power demand?
60% is 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% that's gathering and processing on the gas side. CO2 and then you've got you know a little bit of some of the other business unit products and terminals and then you know it could be exports to Mexico it could be industrial demand other things on the natural gas side.
And of the 10 billion backpack log what can you share a little flavor there I I don't know that you're going to get 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, you know, 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, you know, potentially, you know, 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 of your...
It is. It is. 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 it's largely heavily focused across the southern United States, just like the existing portfolio of approved projects is. And largely natural gas.
If I think about monetizing that $10 billion backlog, think about roughly a billion dollars a year of maintenance CapEx for you all, two and a half to three of dividends, and you're comfortable spending about three a year of CapEx to sort of move that backlog through the system. Is that the right math? Is three billion the right number? How do you get there?
I think three 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 you know after you pay the dividend after you pay sustaining there's give or take three billion dollars now that three billion dollars you know 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 you know 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 balance 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 three and a half to four and a half times. Right now, we are sitting at 3.6 times, so at the low end of the range. We expect we'll end the year about 3.7 times because we did a $500 million acquisition. We don't get all the earnings this year, so that'll push it up a little till we get a full year of earnings. But every point one turn on the balance sheet is worth $800 million of capital. And so, you know, you can spend significant capital on top of the $3 billion that we can spend just from cash flow that we produce. And then theory, further down the line jvs or partnerships would be another source yeah i mean our view is that there is unlimited capital for good risk adjusted return projects and so you know where we you know 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 a issue with that at all and so then when you get these projects
across your desk or across the boardroom 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 a year one EBITDA multiple. The year one EBITDA multiple is more to facilitate for investors sort of the cash flow that we expect to come off or 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. You know, 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, you know, 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 does, and a gathering and processing natural gas has a higher IRR target than a transport project that's backed by a 20-year contract with a 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, you know, 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 haven't had to ration any capital. So, if they're hitting the return hurdles and, you know, we're getting the right credit, and then I think, you know,
those projects are getting approved. Any organizational capacity limits, right? Do you of an organization that can spend $3, $4, $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 operations 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 prepared for that. I think, you know, if you added significantly to that, then, you know, 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, you know, to get your permit and, you know, to get the procurement done. And so a lot of times what those projects are going to do at this point is they're going to start filling out the back end of the build cycle. And the projects that come on more quickly, and so they might fill in during the existing build cycle, those are going to tend to be smaller just because they're going to either not need a 7C from the FERC, or they're going to be interstate, intrastate projects where you don't have the same approval process, or they're going to be gathering projects. But I think, you know, the big, big projects largely are, 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, it'll start pushed towards the tail end of the current.
And then process, filters, appetite for M&A, and then dispositions. How do you keep them 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, you know, it competes for capital the same way the expansions do. You know, 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, you know, 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've said, we don't have any programmatic share repurchase. Our share repurchase is opportunistic.
Some questions are coming in. One is we can't have a session without talking about turbines. With materials, turbines, compression, lead times, et cetera, so far out, what type of timeline are you operating on for new projects? And maybe more broadly, what are some of the constraints you would worry about?
So we have lots and lots of discussion with our vendors on this. And so right now, you know, 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 that require 7Cs. The long pull in the tent has been the FERC 7C application. But with this administration, you know, 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 timelines for procurement. But we're not quite there yet okay so with a little bit more permitting improvement you know then what you'll see is procurement could become the longer pull in the tent but you know we are the way we handle it is as soon as we approve a project we order the pipe and we order the the compressors for the for the pipeline and And we've been in discussions with our vendors about that for months in advance of that.
Yeah, it's funny. The day that government permitting is faster than the supply chain, I don't know, is that a good thing or a bad thing?
Yeah, and, you know, 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 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 all depends on the risk profile. So obviously, you know, larger projects, you're going over long stretches of land. You know, that comes with a certain risk. Smaller projects are typically you've got a shorter build, right? So that, you know, it may have less risk from that perspective. You know, it's all but, you know, you have to look at the counterparty credit. You know, when you're doing the longer builds, you may have a utility credit. You're doing shorter builds, you may have, you know, 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 bigger or smaller. the bias is about the risk and the return.
Yeah, the upstream side. Sometimes you can do the large anchor project, live with a 12% to 15% of return because all of the tiebacks are super high return.
I don't know if that analogy works. Okay, 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, you know, we need to get to a certain minimum level of return on the anchor project. But, yeah, 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?
On 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. You know, that project, we are under construction today. And, you know, that project delivers in the first quarter of 2027. Now, that project has multiple phases, so it stages in over 27 and 2028. MSX we're expecting our first certificate this summer and then that comes in in mid-2028 and then South System 4 comes in at the end of 28 and the end of 29 it also has two phases and as I said most our average in-service date is the first quarter of 2028 on the entire 10 billion so you know we've got a lot of growth coming um over over the next few years um you know i think 27 probably less of it than 28 and 29 have more of the growth that comes from that
comes from the backlog and then in our last two minutes you know ultimately what's the value proposition for investors in the room and beyond owning your stock yeah i mean the the the it's an
attractive dividend and nice growth. And the dividend, you know, is about three and a half percent right now. You know, we have been growing that dividend modestly. That dividend is well covered. It's about a 40% payout on cash flow from operations. We cover it by about two and a half times. It's underpinned by 65% take or pay contracts, 26% fee-based business. You've got a very strong balance sheet, BBB rated, BBB plus rated or 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 you know in the you know with taker largely taker pay contracts and a business that we know well on the ten billion dollar approved backlog and the potential for more to come fantastic thank you Kim
thank you audience look forward to seeing you in further sessions