Kinder Morgan Aktie

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 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 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, 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, right? 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 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. And LNG 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 pipeline 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 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 2 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 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. 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. 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 if we talk about connecting that demand or that supply to demand, I know where all the LNG terminals are going to be built. 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 you've 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. 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 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 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 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 is the potential for projects out there as well. And 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 a lot -- we're going to end up talking about your $10 billion of projects line of sight clear.

$1 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, 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 3 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 on 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, 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 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 -- we've got rough 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 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 not in the beginning of the crisis in 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, just physical limitations, and that gets solved one or 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 I 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 -- 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 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 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 3 years on average. We don't really have anything that's 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 Jones Act.

You keep the Jones Act 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 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 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 right now, the environment is great, but environments can change as administrations change. And so I think that 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. 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 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.

Yes. Touching on that a bit. If we could bring Northeast New York -- I'm sorry, 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 you -- 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 -- 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 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 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, 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 -- 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 is 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 2 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 is pretty scarce 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 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 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 might know, 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 an opportunity set 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 to date. 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 our 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, 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%, 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. 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 if I think about monetization...

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 billion to $3 billion of dividend. And you're comfortable spending about $3 billion 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 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 3.5 to 4.5x. Right now, we are sitting at 3.6x. So at the low end of the range, we expect we'll 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 $800 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 in theory, further down the line, JVs or partnerships would be another source 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 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 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 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 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 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.

It's -- 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 get -- they're going to either not need a 7(c) from the FERC or they're going to be intrastate projects where you don't have the same approval process or they're going to be gathering projects.

But I think the big, big projects largely 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 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 decent -- 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 you -- 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 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 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 that require seven Cs. The long pole in the tent has been the FERC 7(c) 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 order 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 a bad thing?

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 builds, 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 bigger or smaller. The bias is about the risk and the return.

Yes, 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 returns.

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. 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 had multiple phases. So it stages in over '27 and 2028. MSX, 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 '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. That dividend is well covered. It's about a 40% payout on cash flow from operations. We cover it by about 2.5x. It's underpinned by 65% take-or-pay contracts, 26% fee-based business.

We've got a very strong balance sheet, BBB 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 -- 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.

Good morning, everyone. My name is Theresa Chen, and I am the North American midstream and refining analyst here at Barclays. It is my pleasure to host a fireside chat with Kinder Morgan, one of the premier U.S. midstream companies under my coverage with assets spanning across the country covering multiple commodity value chains across natural gas, crude oil and refined products.

And with us is President of Kinder Morgan, Dax Sanders. Welcome, Dax.

Thank you, Theresa. Really happy to be here. And I've also got with me Peter Staples and Sean Pogue, our 3-person massive European entourage here. So great to be here, and thanks for hosting.

Love it. So diving right in, maybe we look at the macro side of things first, Dax. Over the past 2 months and change into the U.S.-Israel war with Iran, how do you think the energy landscape has fundamentally changed with respect to the U.S.'s role in liquids energy supply, in particular, right now, what is the tone like in your conversations with producer customers amid the emergent call on U.S. onshore production? And maybe bridging that to your near-term expectations as well, what is your view on the time you're likely to see a step-up in activity across your...

Yes. Great question. I think all of us, certainly within the energy scope are reacting to news that changes seemingly by the hour. I think it -- with respect to long-term changes, it's pretty early to tell exactly what's going to change. I think certainly, our conversations with -- our direct conversations with producers haven't suggested yet that there's going to be a massive change. I think producers generally are looking for -- and this is part and parcel with the substantial cash flow discipline that's been imparted on U.S. producers over the past 10 to 15 years are looking for really long-term price signals before making substantial changes.

In fact, I saw an interview with Mike Wirth yesterday saying Chevron wasn't really making any changes at this point. Now I did see -- I haven't digested all the news in the last couple of days, but I did see, I believe, Diamondback, who's a large Permian producer as part of their reporting yesterday suggested that they were going to increase production -- crude production in the Permian. So I think if you see sustained price signals, I think you will see incremental production by U.S. producers.

Now that's really with respect to overall price response. If you look at the overall structural underpinnings of world energy production, world energy supply, I think there are probably going to be a lot of thoughts and conversations on where people are sourcing molecules of gas and barrels of oil vis-a-vis sovereign risk. And if people are looking at places and deciding that a particular place with the Strait of Hormuz being front and center, has a lot more risk than it maybe did 3 or 4 months ago than -- and they're looking for places that have less perceived sovereign risk. I think the United States is probably one of the first places they look.

And I think -- I mean my personal view is over the long term, this is going to be a substantial catalyst for incremental development, both with respect to production and associated infrastructure in the United States. And the first place, you're probably from an oil perspective is the Permian Basin. I mean Permian produces roughly -- it's the most prolific U.S. basin of about -- U.S. produces somewhere around 13 million, 13.5 million barrels a day of oil. I want to say about 6.5 million of that comes from the Permian Basin. It also is a substantial provider of gas, roughly 23 Bcf a day of gas coming out of the Permian. And that really is all driven by oil production.

It's -- we call them associated gas because oil is what drives the production decision, but gas comes out. And a couple of things. First of all, you can't flare it, you can't burn it, and it also has value. So that's led to a pretty substantial build-out of gas egress out of the Permian over the past, call it, 10 to 15 years. And so that's probably the first place you look from a crude perspective. With respect to gas, the -- I think of the world gas -- the world LNG ecosystem as being roughly 60 billion cubic feet a day, something like that. I think nameplate is greater than that, but if you factor in utilization rates, it's probably somewhere in 60 Bcf, maybe 65 Bcf. Right now, it looks like the best numbers, at least, I think that we have are that roughly a couple -- 2 to 3 Bcf a day of liquefaction capacity in the Middle East coming from Ras Laffan/North Field is out and going to be out for roughly 3 to 5 years. Now that could change. I mean the amount that's out could change tomorrow, but that seems to be what the number is right now.

U.S. liquefaction capacity is expanding. It's about 21 Bcf a day right now, up from a blending of about 15 Bcf a day in 2025, but it's effectively maxed out right now. There's incremental capacity coming online. And if you look at the basins that could provide that, the Permian is certainly one of those. The Marcellus, which is the biggest in the U.S. at about 36 Bcf, but it's reasonably constrained with egress capacity. And then you've got the Haynesville, which is right next to LNG corridor at about 15 Bcf or 16 Bcf. So that looks -- that's the landscape as we see it right now.

Super helpful, lay of the land as far as the key drivers and where everything is coming from. And Dax, I want to double-click on the commentary related to the call on U.S. LNG, supporting incrementally positive long-term growth outlook for feed gas operators like Kinder Morgan.

So we're still somewhat early days in the next wave of announcements and proliferation beyond what's been already under development. But what are you hearing from your liquefaction customers at the end of your pipelines in terms of additional expansions from here as a result of this call in the war? Do you anticipate further upward revisions to your already bullish outlook for feed gas demand growth as a result of all of these developments?

Yes. I think so. I think it goes -- it's part and parcel with, first of all, the capacity that's actually been taken off right now. And I think as well as kind of the thing I touched on with respect to the people's perception of sovereign risk. So I think that -- we think that right now, the U.S. gas market is about 115 Bcf a day, roughly 115 Bcf, 116 Bcf. We think that's going to grow or rather the latest WoodMac numbers suggest that's going to grow by roughly, I want to say, 19 Bcf over the next 4 or 5 years. Our numbers are actually a little bit more bullish. LNG growth is about 13 Bcf of that. So a pretty substantial piece of it. And we think that is -- that's going to continue. And you take one specific, and I don't have any information from this group, but you take Golden Pass LNG, which is one of the largest facilities coming on here pretty soon. That's 30% owned by Exxon and 70% owned by the government of Qatar.

The government of Qatar clearly owns and runs Ras Laffan and is the developer of the North Field, the largest -- presumably the largest field in the world. I think that it's probably reasonable to assume that their calculus over the last 3 to 4 months about what's the most practical to further develop has probably changed a little bit. So we feel good about that. And we've got -- one of the ways we're playing it, and we think that our angle in this as an infrastructure company is to build the infrastructure around the assets like LNG that are going to be key assets.

We have the largest natural gas network in the United States. We transport about 40% of all the gas around the United States, about 40% of the liquefaction capacity or gas going into liquefaction. And we've got -- right now, we've got a backlog of projects, and these are projects that are Board approved that are -- that have signed binding agreements with creditworthy counter-parties that we are deploying capital, actively deploying capital against. And that capital is -- about 60% of that backlog is actually related to power in the United States, but about 20% of it is related to LNG.

And one key pipeline we have on the LNG front is -- we call it the Trident pipeline is a pipeline that originates in Katy, Texas and goes north of Houston goes to the Texas-Louisiana border, ties into our network and some other pipes in the Texas-Louisiana corridor. It will transport about 2 billion cubic feet a day of gas. And this is gas that's coming out of the Permian. I talked about it earlier, that's moving into the Houston area. But there's only so much that Houston can absorb. It needs to move east into the markets East. And so we're building this pipe. It will be -- it will start to come online towards the end of next year, and it will be -- it's under active construction right now.

And it will come in over the next year, sort of following that, get to a full run rate after that. And so it will really take -- it will be a connector for Permian egress gas and moving it into the LNG and even to a lesser extent, power consumption corridors. And on that pipe, we've got -- we will have the ability to expand that pipe by an additional Bcf a day with just compression should the need -- should the basin continue to expand and the need arise...

And on that brownfield expansion, would that be rather quick in terms of turnaround and commercialization in your opinion?

Yes. We haven't fully scoped out what it would be. But generally speaking, compression expansions, as you noted, a brownfield compression expansion can be done a lot more quickly than a greenfield expansion where you're putting new pipe in the ground. So it definitely will be -- would be a lot -- we would be able to get it done a lot more quickly than the time line for this pipe, which is all greenfield new pipe in the ground.

Understood. So in addition to your sanctioned backlog, of which consists Trident and other things, I'd like to touch on your $10 billion of shadow backlog of natural gas projects and other projects. Can you share more details on these proposed opportunities, which are closer to reaching FID even from a value chain perspective without naming individual ones? How much more of this shadow backlog could you realistically sanction in the year ahead?

Yes. So just again, a little bit of a recap on -- because these are measures we use to communicate with investors on sort of what the future looks like and what we think we can develop. So again, starting with what we call our project backlog, which to reiterate what I mentioned a minute ago, those are projects that have been sanctioned that have binding proceeding agreements, long-term agreements that we are actually actively developing, spending money on. That stands right now at $10.1 billion. We just updated it recently.

That consists of projects that I said earlier, about 60% related to power. And again -- yes, sure. yes, yes, about 60% of our projects are power related. And within that, I mean, data centers get a lot of conversation in airtime, but the power demand that -- first of all, these contracts are generally with utilities. They're not directly with data center providers. They're with utilities that have generally solid investment-grade ratings, generally sort of an A- kind of level.

And they're for power related to everything from demographic changes, migration into the U.S. Southeast, coal to gas switching and power, reshoring of industrial demand in the United States as well as data centers as well. But I think the point is, is that there are a lot of drivers that we're seeing in our markets for incremental power that are beyond data centers. So -- and then about roughly 20% is LNG and the balance is other stuff, industrial, miscellaneous other things. So that's our backlog. Our shadow backlog that Theresa mentioned is another measure.

I mean investors have constantly asked us, well, what's next behind that? And so we've developed what we call our shadow backlog, which are projects that are under active development by our business development teams. What they are not are an idea that's a hope and a prayer that somebody just kind of came up with over lunch and sketched out on a napkin. What they are opportunities that we are in active conversations with customers on. We know that there is a demand. We know that there's a possibility of a project, but they haven't been approved by the Board.

They haven't been -- we don't actually have signed agreements yet. It may be a situation where we've got competition, and there's a lot of competition out there. We have competition with other potential providers or a customer may just decide to go in a different direction. So -- but these are projects that we believe have a really good chance of being developed. And generally, what will happen is over kind of a year's period of time, the projects on that list will work themselves out. And we will either get -- some of them we will get -- a lot of them we will get, some of them we won't. There will be new ones added. Some of them will go away. As we sit here right now, our shadow backlog looks a lot like our existing backlog. There's a lot of potential power demand out there.

Largest area of demand is probably the United States, as I mentioned, Southeast, which is where we have our Southern Natural Gas pipeline, which is a joint venture with Southern Company, the big Southeastern utility, which has a lot of power demand. There's also the Desert Southwest, where we have our EPNG pipeline out West. Again, there's a lot of competition out there with the Transwestern Pipeline. And in the Midcontinent as well, where we have our NGPL, Natural Gas Pipeline Company of America that we own 37.5% of. So those are really the drivers behind kind of what we're seeing in our shadow backlog. But there's a lot of opportunity in the U.S. infrastructure market.

Got it. So between shadow and sanction, $20 billion of potential opportunities out there, $10 billion and change of which has been officially sanctioned.

Yes, that's right.

Looking at data center side specifically, can you talk about Kinder Morgan's role in the SoftBank consortium, organized to develop a 9.2 gigawatt data center project in Ohio. Will KMI need to expand your existing footprint in the region? What will you need to do to serve this project?

Yes. Great question. And what she's talking about is there was an MoU that was released by the [indiscernible] it was actually released by SoftBank or U.S. federal government. But it effectively is a consortium of people led by SoftBank and led by a big source of capital from the government of Japan as well as a host of other people looking to invest a substantial amount of capital in the United States for data center development in different places.

We were named in that as part of that consortium. We are thrilled to be part of it. We're thrilled to be working with SoftBank and the other members of the consortium. There hasn't been -- and the potential opportunity associated with that is not part of any backlog anywhere. We don't have any signed binding definitive agreements. But we do continue to work with the consortium, and we hope that's going to lead to something at some point because the development is real, and we think there's a good opportunity. But we haven't announced anything. We haven't put any direct releases out ourselves. And again, just to reiterate, there's nothing associated with that in any one of our backlogs.

Understood. It is interesting that you're the only midstream company named within that consortium period.

Yes, that's right. And we were very happy to be the only one named in there. So...

So we talked a lot about your organic growth opportunity stacks. I'd like to touch on the inorganic side. Looking at your recently announced acquisition of Momentum (sic) [ Monument ] Pipeline, can you shed more light on the strategic benefit that this asset will bring to your system and as well as the rationale behind purchasing an asset that is comparatively more expensive than what you typically build on your own?

Yes. Great question. And just to be clear, it's the Monument pipeline that we -- no, it's all good. There's a lot of Ms out there. We -- yes, so the Monument pipeline which we announced with our earnings a couple of weeks ago, and we actually just closed on that last week. The -- it's an acquisition just north of $500 million. This is a short-haul piece of pipe just outside of Houston that ties really nicely into our existing network. It's got a set of customers, a small set of customers with the largest customer being a customer that is one of our largest existing customers on the same asset.

And so we look at a lot of M&A -- potential M&A transactions. Anything that's close to what we do, we look at. We're always looking at something. Most things we're not going to get. Most things, we're just -- there's some buyer that's probably willing to take more risk or underwrite more -- less concrete assumptions than we are. But if you look back over the last 5 years, I would say about every -- somewhere between, call it, every year, but call it, 6 months to 18 months, something will come along that is just an absolute fat pitch right down the middle of the plate. And this was one of those. It's a pipe that, again, ties right into our existing network.

There's an existing storage contract associated with this that the asset is that the seller had been using to supply storage service to the existing customers. We've got our own storage assets over time, we will transfer the storage, the providing of the storage service from the third party to our existing assets, and we've got some incremental capacity there that we're not using. So it's a really nice tuck-in acquisition. And exactly to your point, we are -- we're, I think -- as you noted, when we build new pipe, we generally are able to construct it at a multiple -- at a very attractive multiple. Our existing backlog, as we talked about, is about 5.6x build multiple. And our history suggests that we can do that or better with new projects.

Now even in the M&A market, even when we find an asset that we think is a really good fit, there's a lot of competition out there. And so generally, the price and the valuation for M&A assets is not as attractive as we would see on new build multiples, but still very attractive. So as we said, in the medium term, this will be sort of an 8x asset, and it's something we're very excited about, and I think it will be a really good tuck-in over time.

Great.

It will be a really good tuck-in day 1, but it will be really good over time.

Understood. And we talked a lot about your Gulf Coast assets as it relates to natural gas. In terms of the Permian needing additional residue gas egress, you clearly have a strong footprint there as well. Can we talk about your ability to execute on incremental expansions of GCX or any other flavor of Permian egress as you see fit as this demand grows over time?

Yes. Yes. Great, great macro question as it relates to us. So the interesting thing about Permian, we talked about the Permian at the beginning of the conversation, but the interesting dynamic about Permian gas is -- Permian gas egress is that it has -- egress was needed. There was almost no egress, call it, 10 years ago. And gas production started to grow and egress was needed and egress -- a decent bit of egress was built. And there was a lot of speculation and worry that the egress was getting overbuilt.

And guess what, gas production just continued to grow as the Permian grew and egress grew as well. And so we've kind of had this sort of one step, one foot in front of the other, incremental egress, incremental production growing. As we sit here today, the Permian is short gas egress. And really, what you do is you look at the difference between the Waha price and the Houston Ship Channel price and Waha is pretty consistently negative and which is, again, is the price in West Texas. We've got an expansion of our GCX pipeline we own, our 2 -- we've got several, 2 main and then a couple of ancillary pockets for egress out of the Permian heading eastward. We also have our El Paso Natural Gas pipe, which moves gas westward out of the Permian. But we've got a 570 Mmcf a day expansion of our GCX pipeline, which is coming online sort of like -- it's in the process of coming online right now. It will be in later this quarter.

With that, our pipes moving eastward are generally at capacity based on the amount of steel in the ground. There's also an additional 11 Bcf. I want to say it's about 11 Bcf of capacity -- egress capacity coming online with some other pipes, Hugh Brinson with Energy Transfer is building Eiger, a couple of other pipes. So as those come online, it feels like you're going to be -- you're going to have enough egress capacity out of the Permian.

Now again, if you go back to what we started talking about at the very beginning, if there is a call on additional Permian crude capacity or Permian crude production and Permian gas grows, you could be short again. And I think if there is a new greenfield pipe that needs to be built out of the Permian, I think we certainly would be there and be ready to participate in that. You could potentially even see another pipe, not compression, but looping of one of our systems coming out of there.

But again, just to reiterate, I think we are very well positioned to be able to take the gas. As it comes out of the Permian and moves eastward, it moves right into our network, into our Texas Intrastate system, potentially our Trident pipeline that we talked about. So we're very well positioned to move it even -- move it further eastward.

I think, Dax empirically speaking, the supply and demand balance for Permian egress has only surprised one side.

Yes.

We'll see.

Well said.

So turning to the liquids side of your portfolio. I want to give some attention to this, too, because you have some major development and projects here. So maybe first on what's recently been in effect. Your conversion of your Bakken system from crude oil to NGLs. Looking at that recent pipeline conversion, how do you think about the incrementally positive macro backdrop, the potential uptick in production at large for the U.S., what that means for the Bakken and how that alters expectations for subsequent phases of your NGL system as it stands?

Yes. So just to put a little finer point on what Theresa is talking about, we've historically had a crude pipe -- a crude egress pipe out of the Bakken that originates in the Bakken and goes down to Guernsey, Wyoming. We announced a couple of years ago the intention to convert that into a natural gas liquids line to bring natural gas liquids out of the basin. And that's in the process of coming online right now.

We've talked about potential future phases of that. And we don't have anything that we've announced on that. And I think as we've said before, given how competitive it is up there, that's not something that we've elaborated on a lot. although I would say we do put -- we are putting a lot of energy in sussing out the next opportunities there. With respect to the overall macro, we don't see the Bakken as having a tremendous amount of growth associated with it.

But that's okay from a gas. And we also have a crude oil as well as gas gathering operation in the Bakken. But we don't necessarily see that as absolutely necessary to potentially drive growth. I think the wells up there are getting a little bit gassier. So we are seeing incremental gas, and we are seeing incremental NGLs. So we think that there's opportunity to further develop our Phase 1, and we continue to work on that, but we haven't announced anything beyond that.

Fair enough. Elsewhere on the liquids side, touching on your refined products project. So on Western Gateway, following the conclusion of a successful second open season, can you provide color on the early learnings from both open seasons and whether your expectations for the project have changed at all relative to initial expectations?

Yes. Great question. I would say, first of all, expectations right now are reasonably consistent with what we thought about from the beginning. The interesting thing is the Desert -- the plumbing for refined products in the Desert Southwest in California has been in a relative state of equilibrium for the past 70 years. And what we're attempting to do with our partner, P66 is completely change that plumbing via this Western Gateway project that we're talking about. And the real change, the dramatic change that's happened over the past handful of years is you're seeing refineries in California shutting down. You've seen several -- you've seen a couple of convert to renewable diesel. You've seen a couple of shutdown.

And so refining capacity in California that has traditionally provided refined products to California and even moved products eastward into Nevada and Arizona is changing pretty dramatically. The other thing that you're seeing is the relative economics of PADD 2 refiners and even PADD 3 refiners has increased. And so what this project will do is reverse the flow of one of our pipes that's moving refined products from Southern California into Arizona to take products that will be brought from PADD 2 and Texas Gulf Coast eastward -- I'm sorry, Westward into the Phoenix area and take product from Phoenix to supply California. And what this does, what it would do is provide really the next phase of refined product security for consumers in the Desert Southwest, in Arizona, in California.

And so it's a big undertaking, but it's something we're excited about. The open season, as we said, was successful. The next phase, as we said, as I said on the earnings call a couple of weeks ago, is to negotiate a successful joint venture with our partner, P66, which we're working on. And we're optimistic that we'll get there and that we'll get it done. I mean there's enough -- big enough size of the pie to make this project work. But I mean, again, I think it's likely that we do. But if we weren't able to work something out, then we would go back to -- I mean, these are great assets that we have, and we would go back to the state of equilibrium that existed for the past 70 years. But we think this is a project that the market needs, and we're excited about it.

Well, on behalf of all California residents, we greatly welcome incremental refined products flowing into our state, I certainly hope this project passes FID. But to your point about the state of SFPP at this point, there is a lot of debate on the value of SFPP as it stands, either as contribution to this project or on a stand-alone basis. Can you talk about the EBITDA and earnings outlook for SFPP if this project was not to come to fruition? How do you see that evolving over time?

Yes. Well, first of all, these are really good solid assets. They're good cash flowing assets. They are assets in markets that are -- that have existed for a very long time with solid demand. There are certain places that they serve that have really favorable demographics. I mean, Maricopa County, both our East Line and West Line serve Maricopa County, which is where Phoenix is, which is a very fast-growing metropolitan area. We, in part, also serve the Calnev pipeline, which is serving Clark County, Nevada, which is growing as well.

So these are really good, solid growing assets. They've got really good traditional fixed cost economics associated with them. Those of you that know the way refined products and oil pipes work in the United States, every 5 years, the FERC sets an index adder or subtractor that you apply to the producer price index that sets effectively how much you can raise your tariffs each year. And so it's an inflation plus or minus. The past 5 years, it's been PPI plus 0.78%. FERC just reset it for the next 5 years at minus -- roughly minus 0.5% but again, that's off PPI, which is a substantially positive number.

So what that does is it provides an inflation escalation component to your tariff that allows you to raise -- basically grow revenue each year. So these are really strategically important assets. They cannot be replicated. You're not going to build a new gasoline pipeline in California anytime soon. And they are absolutely critical to meeting the demand that exists today. So these assets are -- these assets are going to be worth a decent valuation whether this -- whether they go into part of this JV or continue to operate as they have for the last 70 years.

Fair enough. And we spent the bulk of our time talking a lot about your fee-based assets, the fee-based contracts and the long-duration nature of those cash flows. But you do have a modest amount of torque within your system as it relates to this macro backdrop that I don't think we can ignore given the current environment. I'd like for you to talk about this potential uptick if either producer activity materializes or the elevated and volatile commodity price environment persists. Can you elaborate on the specific sources of earnings upside across your diversified footprint.

Yes. Well, the first thing I would say, even one of the most important aspects of our entire network, and this goes for the entire United States natural gas grid, but the utilization of our network back in 2016, 10 years ago was about 74%. And today, that number is at or north of 90%. So what that says is the competition for the incremental molecules -- space molecule in our pipelines just continues to increase.

And so we are able to benefit from that when situations -- when the right situation presents itself in extreme events like extreme weather events. So you've got that. That's probably the most fundamental thing associated with our business. But to your point about specific items related to torque, we do have our CO2 business, which is a tertiary oil production business. That business is a small part of our overall company. It generates about $300 million a year of free cash flow. We generally hedge about 90% of our budgeted barrels going into a particular year.

But we've got 10% that are generally floating throughout the year, to the extent that we outperform, we have the ability to capture that. We are outperforming in our crude production this year. We have a Transmix business where we are buying downgraded product and then upgrading it back to what it was before it was downgraded, so we get to capture that spread. We've got some Blending businesses. And then we've also got businesses that are -- those are kind of specific. We don't -- we do not have a lot of commodity exposure as an overall company, but that just highlights some of the areas where we have a little bit of commodity exposure.

With respect to volumetric exposure, I think to the extent you're seeing a lot of incremental volumes, if you're talking about torque, if you have high prices and then you have volumes that are driven by that, we've got gathering and processing. We've got a couple of Gathering and Processing businesses, I mentioned Crude business in the Bakken. We've also got a Gas business there. We've got a Gas Gathering and Processing business in the Haynesville. And then we've also got probably the largest number of export docks that accommodate refined products exports in the United States, and those are running about as full as they can possibly run right now. And we've also got crude pipes that have some exposure to the crude export market. So those are all things that are, again, the fundamental piece of our business is we are a Fee-based energy infrastructure business. That's our core business. But to your point about where do we have some torque, we do have a little bit of torque around the edges that we're able to capitalize on.

Wonderful. Well, we are about at time. Thank you all for participating and coming. Thank you very much, Dax, for this lovely discussion.

Thank you. Thoroughly enjoyed it.

Good afternoon, and thank you for standing by, and welcome to the First Quarter 2026 Earnings Results Conference Call. [Operator Instructions] Today's conference is being recorded. If you have any objections, you may disconnect at this time.

It is now my pleasure to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. As usual, before we begin, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

Now I'm preparing for this investor call, I look back at the text of the introductory remarks I've made over the past several years. Most of what I've said concern the future of natural gas demand and the positive impact it has on midstream energy players like Kinder Morgan. In almost every case, the projections I may turn out to be understated. In other words, the demand for natural gas, driven primarily by growth in LNG feed gas demand and by increased utilization of natural gas for electric generation has simply grown faster than we expected.

Now I think events since the last call have made the outlook for growth even more positive. Regarding LNG demand, the recent events in the Middle East will clearly have substantial impact. While the ultimate outcome is certainly not clear at this point, the damage to Qatar liquefaction facilities and continued uncertainty regarding ship traffic through the Strait of Hormuz will lead to more preference for U.S.-sourced LNG and the predictions for growth in gas-fired electric generation have also increased.

In a piece that surfaced just this week, S&P Global Market Intelligence reports that utilities plan to add a staggering number of 153 gigawatts of gas fire generation capacity in the next several years primarily to serve data centers with the bulk of this coming online by 2030. Now this is twice the estimate by the same group of 1 year ago and reflects plans to build about 210 additional natural gas-fired facilities.

Our Kinder Morgan forecast for overall U.S. gas demand now extends through 2031, and estimates demand in that year of 150 Bcf a day and growth of about 27% from this year. In short, the natural gas story has legs and Kinder Morgan's strong start to 2026 that Kim and the team will explain supports that view.

While the old saying that rising tide lifts all boats has some applicability to this situation, there will clearly be some players who will benefit more than others from this positive story. I believe that the midstream sector as a whole will be one beneficiary, and it offers a low-risk way to invest in the growth story of natural gas, given the prevalence of long-term throughput agreements with investment-grade credits underpinning the bulk of midstream assets.

The Inga Foundation in a study released in March estimates that North America needs 70 Bcf a day of new gas pipeline capacity by the 2050 time frame. And I believe Kinder Morgan will fare very well in this environment. Let me tell you why. We have a superb set of assets located in the areas where gas demand is growing dramatically. Our strategy is to concentrate on expanding and extending those assets in an aggressive but disciplined manner.

This means we will continue to identify and pursue the myriad of growth opportunities we are currently seeing and once undertaken to complete the resulting projects on time and on budget. Because our cash flow is very strong, we will be able to finance these projects primarily with internally generated cash flow, and I can promise you an intense and unrelenting focus on these unparalleled opportunities.

This strategy will enable us to grow our EBITDA and EPS substantially over the coming years as these projects come online, while still maintaining a strong balance sheet and growing our dividend. To me, that's a pretty good recipe for success.

And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. We had a remarkable first quarter. The best I can remember with adjusted EPS up 41% and EBITDA growing by 18%. Importantly, every segment delivered growth versus the first quarter of '25 and every segment outperformed our budget. Natural gas drove the most significant share of the outperformance, benefiting from winter storm burn and the extended cold in the Northeast.

These results reflect the value of our critical infrastructure and the essential role it plays in serving our customers, especially in periods of high demand. During the quarter, we entered into an agreement to acquire the Monument pipeline system in Texas for approximately $500 million. These assets are a natural fit with our existing network, supported by long-term contracts and acquired at an attractive multiple. We received early termination of HSR yesterday and expect to close by the end of the month.

On full year guidance, we now expect to exceed our EBITDA budget by more than 3%, excluding any contributions from the Monument acquisition. Most but not all of that outperformance is attributable to the first quarter. Given that we are still early in the year, we've taken a somewhat conservative approach to our expectations for the year. However, continued outperformance in our gas group and/or higher oil prices, which benefit our 10% unhedged oil in the CO2 segment could provide upside for the balance of the year.

The growth in the overall natural gas market of over 36 Bcf since 2016 has driven utilization on our five largest gas pipelines to over 90%. That utilization, combined with the projected growth in the market to approximately 150 Bcf a day in 2031, highlight both the need and the opportunity for expansion. Our expansion project backlog increased to $10.1 billion this quarter, up $145 million from the last quarter. We put approximately $230 million of projects in service and added $375 million in new projects, including three data center deals.

The backlog multiple remains below 6x with an average in-service date of Q1 2028. With respect to our three largest projects, which make up over 50% of the project backlog, we continue to be on time and on budget. Beyond our reported backlog, we're actively advancing a number of identified opportunities. Much of this activity is being driven by power growth, and we expect a meaningful amount of these opportunities to convert into approved projects during 2026.

Our performance this quarter demonstrates the strategic positioning of our 78,000 miles of pipeline and 136 terminals and the tightness of energy infrastructure. As we look ahead, we're confident in our ability to complete our $10.1 billion backlog of projects, add to that backlog and deliver tremendous value to our investors.

And with that, I'll turn it over to Dax.

Thanks, Kim. Starting with the natural gas business unit. Transport volumes were up 8% in the quarter versus the first quarter of 2025, primarily due to increased LNG feed gas deliveries on the Tennessee Gas Pipeline. Natural gas gathering volumes were up 15% in the quarter from the first quarter of 2025 and increased across most of our gathering and processing assets with the largest impact coming from our Haynesville system.

Winter Storm firm and the extended cold weather in the Northeast contributed to higher volumes as well. Looking forward, we continue to see incremental project opportunities across our natural gas pipeline network. For example, we're in various stages of development on projects to serve more than 10 Bcf a day of natural gas demand in the power generation sector and opened 3 Bcf a day in the LNG sector.

In our Products Pipeline segment, refined product volumes were down 2% in the quarter compared to the first quarter of 2025 and crude and condensate volumes were down 12% in the quarter compared to the first quarter of 2025, with more than all of the decline in crude volumes explained by the removal of the Double H pipeline in service for NGL conversion in the third quarter of 2025. Excluding Double H volumes in both periods, crude condensate volumes were up 2% in the quarter compared to the first quarter of 2025.

With respect to Western Gateway, as noted in the joint release earlier in the week, KMI and Phillips 66 recently concluded a successful open season on the proposed Western Gateway Pipeline system. The next step is to finalize definitive transportation service agreements with the shippers and hopefully, acceptable joint venture agreements between KMI and P66. Assuming we can reach resolution on the noted definitive agreements, we would expect to FID the project sometime in the next few months.

In our Terminals Business segment, our liquids lease capacity remains high at almost 94%, market conditions continue to remain supportive of strong rates and the utilization of our tanks available for use is approximately 99% in our key hubs on the Houston Ship Channel and at Carteret. Our Jones Act tanker fleet remains exceptionally well contracted. Assuming likely options are exercised, our fleet is 100% leased through 2026, 97% leased through 2027 and 80% leased through 2028.

We have opportunistically chartered a significant percentage of the fleet at higher market rates and have an average length of firm contract commitments of 3 years and over 3 years when considering options that are likely exercised. The CO2 segment experienced 2% higher oil -- net oil production volumes compared to Q1 2025, led by a 5% increase in production at SACROC.

NGL volumes were 5% higher and CO2 volumes were 1% higher. Notably, RNG volumes increased 63% due to greater uptime at our facilities and greater hydrocarbon recovery as the team running that business has made great progress in improving the overall operations of those assets.

With that, I'll turn it over to David.

Thank you, Dax. So for the quarter, we're declaring a dividend of $0.2975 per share, which is $1.19 annualized and an increase of 2% over 2025. As you've heard, we had an outstanding first quarter, generating net income attributable to KMI of $976 million, an EPS of $0.44.

These are 36% and 38% above the first quarter of 2025, respectively. These very impressive results reflect strong demand fundamentals across the country, combined with strategically positioned assets and skilled execution by our colleagues to capture the associated opportunities, and we saw growth across the business segments. The natural gas segment grew the most with colder normal weather, driving additional demand across already highly utilized natural gas midstream systems, but the segment also grew from factors other than the cold weather with contributions from growth projects, greater capacity sales, gathering volumes and utilization across numerous assets.

In products, we benefited from improved commodity pricing as well as the recovery of retroactive rate increases we booked following a favorable court decision. And in the Terminal segment, we had increased volumes and rates in our liquids business as well as the benefit of storage contract buyouts, and we also saw increased volumes in our bulk business. For the full year 2026, while it's still early in the year, we expect to be more than 3% favorable to our budgeted adjusted EBITDA. That's over $250 million of additional EBITDA contribution. We clearly outperformed in the first quarter, and we expect additional outperformance for the rest of the year, driven by continued strong demand for our natural gas midstream services and the contributions from our Monument acquisition will be additive as well.

Moving on to the balance sheet. As we continue to grow our cash flow and remain committed to a disciplined approach to capital allocation, our balance sheet continues to strengthen. Our net debt to adjusted EBITDA ratio ended the quarter rounding down to 3.6x, which is down from the -- down from 3.8x from the beginning of the year. Leverage of 3.6x is the lowest for a Kinder Morgan entity since well before our 2014 consolidation transaction.

That being said, we expect leverage to increase slightly by year-end 2026. We expect increased capital spend during the rest of the year, and we will only get a partial year EBITDA contribution from the Monument acquisition. Our budget had us finishing 2026 at 3.8x, and now we expect to end the year 2026 at 3.7x due to our expected EBITDA outperformance, and that keeps us comfortably below our midpoint of our leverage target range.

During the quarter, net debt increased $82 million, and here's a high-level walk-through of that. We generated $1.49 billion of cash flow from operations. We spent $650 million on dividends, $800 million on total capital, capital expenditures, and we had about $120 million of other uses of cash, which gets close to the $82 million increase in net debt.

The rating agencies have now fully recognized our strengthened financial profile with Moody's upgrading us to Baa1, which means we are now the equivalent of BBB+ at each of the 3 rating agencies. Additionally, the treasury issued guidance in March that will allow us to more fully take advantage of bonus depreciation across all of our assets, and that creates nice near-term cash flow benefits, which will generate additional investment capacity.

With that, I'll turn it back to Kim.

Michelle, if you'll come on, and we will take questions.

[Operator Instructions] Our first caller is Julien Dumoulin-Smith with Jefferies.

Luke on for Julien. Nicely done on the quarter. Just wondering if you could help frame the expected Western Gateway scoping in more detail around like maybe initial capacity diameter, maybe even total project costs and how capital contributions are likely to be allocated between the partners just given the contribution of those assets you have?

I'll say a couple of things, and then Mike Garthwaite, if you want to add anything. I mean, I think as Dax noted in his comments, we've still got to negotiate the JV terms, and that will obviously impact what our capital contributions are going to be. We expect that we will be making, one, an asset contribution, and two, we will be making cash contributions. But exactly how that's going to lay out and the total cost of this project and some of those details I think we'll just leave that for once we get the project FID to get through these discussions, assuming that we get through these discussions with our partner.

Yes. And then I would say on the capacity side, I don't want to go into full detail as we work through and towards executing the final transportation service agreements. But you'll see the maps that we've consistently had out there, our line from El Paso to Phoenix is a 20-inch line that we focused on, and that gets the commitments that we've seen served plus some growth that comes along with that.

Awesome. And separately, you guys touched on this in your remarks, but maybe just looking to the Northeast and potential for maybe any expansion out there. There's this growing recognition that we may need to see more gas degressed into New England. Just curious for your thoughts on whether Tennessee could be a potential solution for that. And if you would need at the state and regional level to take another look at growth opportunities in that part of the state.

The need is clearly there. But I mean, I think we've said this a number of times, we would have to have certainty, certainty on state permits, and we would have to get the commercial support we need to underwrite a project. And last time, the commercial support was a problem. because the IPPs don't really have a way to get reimbursed when they take on long-term capacity agreements.

So you either need the utilities or there's not a lot of commercial support out there. So I think we have to have the commercial support and the permit. Somebody is going to have to roll out the red carpet. And then I think we would love to take advantage of the opportunity. But we've gone down that road once. We wrote off a fair amount of capital. And I think that's not something that we are interested in doing again.

Our next caller is Theresa Chen with Barclays.

Can you talk more about the rationale behind the Monument pipeline acquisition? What kind of synergies or growth opportunities does it provide for your broader system that you would not have otherwise been able to achieve with your existing assets in the area alone? And when thinking about the valuation, can you define more precisely what medium term means in terms of achieving that less than 8.0x multiple? And does it require incremental CapEx? And if 8.0 is indeed medium term, what would be the current or LTM multiple just to provide context as a marker for Texas intrastate gas assets in general?

And that's quite specific. Okay. So let me just say a couple of things about that. $500 million, as we mentioned, we've got long-term contracts that are underpinning this weighted average contract life on this is about 9 years. It's over 90% utilities and industrials with good credit ratings. It integrates well into our existing assets. It does allow us to access some storage on our system that we previously couldn't access.

There is some ongoing expansion activity that will require some incremental capital after we close, and that expansion opportunity will come in over time. I think it comes in and it starts later this year. And so I think that's what will help bring what is high single-digit multiple down is coming from that, primarily from that expansion. There are some synergies with this associated with our storage and I'll let people talk about some of that.

So just taking a step back, a couple of things. One, the system really integrates well on a last mile basis, it goes through Houston all the way down into the corp's corridor. So we see the demand profile there is very strong. It does bring an element of incremental no nitrogen supply in addition to what we are already working on, which over time, we'll see the value of that low nitrogen. And then as Kim alluded to, we -- these assets touch our storage -- our existing storage in ways that we can unlock certain value that an independent by itself cannot. So those are the 3 primary drivers. And once again, it just -- it makes good map is like what I'd like to say, and it fits real well.

In terms of the early termination of the terminal service agreement at Pasadena in exchange for a series of some payments. Did you recognize a lump sum in the first quarter? And if so, how much? And what is the expected lost EBITDA?

So let me say a couple of things on that. Yes, the lump sum gets recognized in the first quarter. And I think this is just a great job by our terminals team so we have the termination, they have gone out and they have backfilled all these tanks. And all these tanks are backfilled on a long-term basis. Some people are taking them currently and then their rate steps up over time as we improve connectivity.

And then one of the other customers is taking it in a year or so, 18 months. But in the interim, we are able to lease that capacity on a short-term basis. So we've been able to backfill all of this, the rates will step up over time and largely offset the lost earnings and with respect to that contract that was bought out, I think there is a little over a year remaining on that contract.

Through first quarter of '28.

Our next caller is Brandon Bingham with Scotiabank.

Just wanted to maybe talk a little more thematically about some of the dynamics you're seeing in the refined products market, thinking specifically around California and Western Gateway. How is demand evolving in light of the products pricing being seen on the screen and just the tightness in global markets? And just could that possibly create any expansion opportunity for the project?

I wouldn't say that it drives expansion for the project because I don't think the overall demand necessarily is changing California significantly. What this -- what I think the global situation does here is it highlights the fact that California has to import some of its supply and that makes it subject to the variability in growth markets.

And so what this does is instead of bringing in a fair amount of product over the water, they'll now be bringing in supply from Texas and from the Eastern United States. The other thing it does is it serves the Phoenix market, which is also right now reliant on the California refining capacity. And as you know, that refining capacity has decreased as a number of refineries have shut. So I think it's a great solution, I think, for California and for Arizona to be able to access domestic supply as opposed to having to be reliant on the international market.

Okay. Great. That's helpful. And then maybe just turning to -- you mentioned continued expectations for outperformance over the balance of the year. Is any of that tied to the dynamics created by the Iranian conflict? And how do those change, if at all, when this conflict comes to, I'll say, a firmer end or hopeful end?

Yes. I'd say the Middle East conflict has limited impact on us. Obviously, in our CO2 segment on the unhedged barrels, which is about 10% of our barrels, we're getting a higher crude price. On products, where you might anticipate it impacting us is just higher product prices impacting demand, but we have not seen that to date.

In our Terminal segment, I think our docs have been really busy. Our export docs have been very busy. And so record volumes across that. And so we do get a small amount of ancillary revenue resulting from those movements. But our tanks are sold on long term, what we can monthly warehousing charges, which are takeway contracts. And then on natural gas, not much in the short term. Obviously, we're moving a lot to LNG export facilities, but those are under long-term take-or-pay agreements. But as Rich said in his opening comments, longer term, it should drive incremental demand for U.S. LNG.

Thank you. Our next caller is Manav Gupta with UBS.

I wanted to ask you a little bit about the GCS expansion and at the same time, the Trident pipe. And what I'm trying to understand is there's a lot of gas moving towards East Texas, including your GCS expansion. And then egress from there to Port Arthur and Henry Hub might take a little more time, including your pipe Trident.

And I'm trying to understand if that might lead to some dislocation in pricing as we understand between Houston Ship Channel, Katy or Agua Duscher, how are you thinking about these localized gas markets as more gas from the Permian starts to pour in over there and the egress might take a little more time.

Okay, Manav. That was a -- I think, a two-part question. So first, both projects are on track. They're moving forward. I think in terms of basis dislocation, et cetera, I generally try and stay away from commenting on forward-looking pricing. But I can tell you, just at a fundamental level, there are always going to be dislocations, right, as you look forward, when you have demand coming on separately, then the supply getting across, and it goes in both directions. So what I would say there is -- is that a possibility?

Yes. I guess the reality is there's also a lot of demand from the power side that we're seeing coming up in Texas. We're talking about the power growth within Texas. So speed to market is very important there, and maybe there's a home for that supply. I'll leave you with that, and then you can kind of draw your own conclusions from that commentary.

And then the other thing I'd say just about our assets is we benefit a little bit on the margin from pricing dislocations in the short term. I mean, obviously, in the long term, those drive expansion projects. But most of our capacity on our pipes is sold under long-term take-or-pay contracts.

So perfect. That power comment is very helpful. My quick follow-up here is KMI is somewhat unique. You have nat gas storage opportunities, which some of your competitors don't have. Can you talk a little bit about -- I think in December, FERC approved a 10 Bcf expansion at NGPL's existing storage. And then I think at Bear Creek storage also, you had an open season. So can you talk a little bit about the nat gas storage opportunities in your portfolio?

Yes. Look, a very good question. And as we see this demand coming on and the scale of this demand, one of the big differentiators, and Rich alluded to, there's midstream opportunities, but there's some differentiator. Storage is going to be a key differentiator for us. We have those expansions on site that we're working on, especially the Bear Creek, not yet commercialized, but it's something we're working on.

And we're looking at that across -- looking at storage across our footprint, not only to be able to leverage these short-term dislocations, but long term, as you think about operational balancing needs that these large demand centers are going to have, the ability to put in gas into storage and also pull out storage on a pretty quick basis is going to be critical for their operations.

And that's somewhere where we think we differentiate ourselves quite nicely, having over 700 Bcf of storage in play and looking at much more to try and expand from an operating footprint standpoint.

Our next caller is Michael Blum with Wells Fargo.

I was going to ask all my questions at once, if that's okay. So first question really is on capital allocation, and it really encompasses both Momentum, this deal and Western Gateway. And the crux of it is you have significant gas pipeline investment opportunities at 6x investment multiples or better.

So I think you addressed the strategic synergies at Momentum. But on Western Gateway, is it fair to assume that the return on this project will need to compete with your gas pipeline investments? And then the second question is on Western Gateway specifically, can you clarify that if you lose any EBITDA from taking an existing pipe out of service for this project, it will be captured in the overall project economics.

Okay. Sure. So I think your first question is, do we look at Western Gateway the same as we look at natural gas projects. And I would say no change in our capital allocation strategy. We continue to target risk-adjusted returns in the same range that we always have. And so yes, this competes with natural gas. And so no change there in our approach. You asked about if we -- let me just say this, we're going to invest additional capital and we're going to get incremental EBITDA, and it will be at a nice return in order to do this project.

Mike, just to clarify one thing. We're buying the monument pipeline, not momentum.

Our next caller is Jean Ann Salisbury with Bank of America.

I had a similar question to Manav's about the Trident staggered start dates. As you mentioned, there's some concern that gas pipelines out of the Permian are going to come on well before gas pipelines to take them further east like Trident. So I guess my question is that if there's pull for more than the 30% of that gas on Trident in 2027, can you deliver that? Or is it really like that's the pace that you're bringing on Trident, if that makes sense?

Yes. I mean Trident is going to come on first phase, first quarter of '27. That's the schedule. And so there's no advanced gas that can get across until we get that pipe up and running.

Sorry, I meant like over the course of 2027, if there's more demand than just the 30% that you referenced in the news release. demand for 100% of it, for example, is that something that you could deliver or it's more of a downstream constraint?

Today, there is some incremental capacity versus what we would move in '27.

Okay. That makes sense. And then I guess my other question was about the NGPL 550 MMcfe expansion in the Panhandle. That seems like quite a lot of gas. And I was wondering if that's basically all demand pull for utility demand in that area or if it's partially people supply pushing out of the Permian and getting on to other pipelines after NGPL?

You're referring to the Amarillo expansion. Yes. Yes. So that is market pull driven by power.

Our next call is Keith Stanley with Wolfe Research.

I wanted to follow up on Western Gateway and just, I guess, how you're thinking about the project. So first, just confirm you'd be contributing the whole SFPP pipeline to the JV. I think that's $350 million of EBITDA or so. And then on the returns, just how you're thinking about it, do you look at it as just a return on the cash contribution you would make to the JV? Or do you also factor in that you're effectively upgrading the value of the asset with new long-term contracts and a more competitive supply source?

Okay. So it's not the whole SFPP system. It is what we call the East line, which goes from Amarillo to Phoenix and it's the West -- and the West line, which now moves product from California to Phoenix -- I mean, sorry, El Paso, I said Amarillo, El Paso to Phoenix on the East Line. And so those are the lines that are getting contributed to the JV. There are additional SFPP assets in California that will not be contributed. And then with respect to your second question, say that again about the EBITDA?

Just the returns, like do you think of it just as cash-on-cash return on your contributions to the JV or you factor in the upgrading of the project?

Well, I mean the way we think about it is what cash are we contributing and what cash are we getting back versus anything we might be giving up. And so we look at it on an incremental return on our capital. And it's based on an IRR. So it's not just what is the year 1 cash on cash, and we look at a full project IRR.

Got it. Second question on the strong quarter. Any color you can give on the impact that Permian gas spreads are having on the business? Is it single-digit millions, tens of millions, hundred million? And then any impact on winter storm fern specifically that you would call out?

I mean, I'll say a couple of things. The Waha-Houston Ship Channel, it does have some modest benefit for us. But our preference and practice for that matter, has been to sell transportation capacity to our customers on a long-term basis. And so what I'd say generally about winter storms is what happens is you just have a peak in demand and therefore, the services that we provide for our customers increase in value.

And whether that's storage services or that's transportation services, when you've got increases in bands, you've got high volatility and you have a system that's running at the high utilizations that we talked about, that just creates opportunity for us. And so I think that's what you're seeing in the first quarter results.

Our next caller is Olivia Foster with Goldman Sachs.

I wanted to start on the gas transmission opportunity set going forward. When we think about the various projects under commercial discussion and the shadow backlog, I understand a bulk of the opportunities are related to growing power demand. Is there any way to frame up other details about the general size or scopes of these projects and potentially as well the geographies from which you're seeing the most demand? We saw several projects move forward today, but what are...

I can describe it generically. I don't think it's really going to answer your question for me to describe this generically. And -- the reason that we don't give more detail around that is because most of these are competitive situations. And so we want to make sure that as we communicate before we -- before these projects are tied down that we don't say something that causes us competitive harm. But in general, I mean, what's in the project opportunity set beyond the backlog, there's a lot of power and there's also a little bit of LNG. There's some industrial, and it goes across the entire Southern United States. So there's opportunities going from Arizona all the way to Florida.

I would add, it's critical to understand, as I'm sure you do, that our pipeline network relates very well geographically to where the big demand drivers are in this country. So I think we are enormously advantaged by the share size and location of our pipelines.

That's very helpful color. I appreciate the details. Maybe for my second question, I'd like to ask about the macro for a moment. Are you seeing any signs of volume changes on your system in response to higher commodity prices, either from a G&P or potentially refined product perspective?

Refined products in the quarter are down a little bit, but we don't think it is a function of higher prices. As I said earlier, we don't think that the higher prices are yet having a noticeable impact on the consumer, but that's something we'll continue to watch. And then with respect to G&P volumes, most of our stuff is gas on the G&P side. Those volumes were up nicely in the quarter. They were up 15% in the quarter. And our KinderHawk volumes in the Haynesville were up 34%. So nice there. Our crude gathering position is primarily in the Bakken, and it's doing okay. Continental dropped rigs earlier this year, but prices are better. And so hopefully, at some point, some of our producers may increase rigs, but we have not seen that to date.

Our next caller is Jeremy Tonet with JPMorgan.

Just wanted to come back, I guess, to the tracking more than 3% above budget. And just wanted to refine that and see how much of that is kind of like onetime in nature versus recurring? Like if we're thinking about for '27 go forward, should we think about how much of that 3% would kind of come back next year on a regular basis versus maybe being onetime in nature?

Well, I think with respect to the buyout on terminals, obviously, that's somewhat onetime in nature. And then with respect to the balance of it, I think that's just going to be a function of, to some extent, commodity prices because on the margin, we do get some benefit from commodity prices. and whether you have winters in the future.

So to the extent that you're getting some good winter weather, system is going to remain tight for a while, we will -- our asset -- the value that our assets provide our customers will continue to be strong in those situations.

Got it. So it's fair to think of that bucket kind of the contract onetime weather, how it shook out and commodity prices are kind of the main drivers there?

Yes. I mean, I think volumes in CO2, production volumes are up. That's nice. And RNG did better. I think we already went through that. So products-based business is very stable and doing well. So I think the base business is performing very well. And then you have this increased demand and increased volatility and increased commodity prices that around the margin are just driving tremendous outperformance.

Got it. And actually, I just wanted to take a step back. We have not heard much conversation on carbon capture in some time now. And just wanted to see in the marketplace, do you see any demand for that? Or is that kind of completely gone away at this point?

I would say it's mostly gone away at this point. We're looking at a few things, but I'd say it's mostly gone away at this point. But I'd say we have the expertise here. And if the opportunity ever presents itself again, and we can do it on an economic basis, then it's something that we'll look at.

Our next caller is Elvira Scotto with RBC Capital Markets.

Given where commodity prices are now, can you maybe review your oil hedging strategy and just how you're planning to hedge out over the next year or so?

Yes. I mean we're 90% hedged for the balance of this year. And I think our $1 move in prices is a little less than $4 million. I think it's like $3.5 million. And then next year, we're like 70%, 75% hedged for 76% hedged for 2027. So -- and I think that's roughly at $65-ish $60 a barrel. And so our hedging strategy is -- remains the same in terms of, I'd say, the near term, we try to hedge a large majority, I'd say, 80-plus percent of the current year.

And we usually, by the time we get into the year, 90% hedged. And then with respect to year 2, we hedge that -- more of that as we move closer to it. And so I think at this point in time, being 70% -- 76% hedged on 2027 is consistent with how we've done it historically.

Years 3 and out, we typically are waiting to lay on some more hedges because some of your cost structure is driven by commodity price. And so we want to make sure that we match those 2 things up. So very stable cash flow in the near term, not huge amounts of commodity -- not large amounts of commodity exposure, some exposure on the margin, I think, is where we want to be.

And of course, to the extent that we outperform our plan, those percentages are based on planned volumes. And to the extent, as we said earlier, we are driving -- having a very nice year as far as volumes, and we'll sell those into the open market, obviously.

Our next call is Jason Gabelman with TD Cowen.

I wanted to first go back to Western Gateway. And I guess 2 clarifying questions there. One, is it in your project backlog? I know it hasn't been to this point, but I want to confirm, it's still not in there. And two, as you think about the steps that you need to complete to FID the project, would you say those are less difficult than completing the open season? Or do you still see a decent amount of risk of getting this project over the finish line?

Okay. With respect to the first question, no, it is not in our $10.1 billion backlog. We don't generally put any projects in there until they are approved/FID-ed, however you guys want to think about it. But -- and then I'll let Mike address whether -- what he thinks is the hardest.

Yes. I think entering into these -- as you go out with an open season, there's just a lot to understand in the market. And I think that was probably the harder piece. As we look forward to executing and getting to FID, there's, of course, the regulatory aspects that we've got to look at. But we've got experience through all the states that we're operating in. We have experience with those regulators and have confidence in moving that forward.

Got it. Great. And my follow-up is just on the commentary around future growth and kind of the more constructive outlook for gas demand in this country and you're talking about seeing kind of aggressive in your growth in your pursuit of additional growth.

Thinking back to the Permian pipeline going west that you didn't win, were there any lessons learned in that process that you're going to apply in competing for future growth opportunities in this country, particularly as you think about the competitive position of your asset base?

I think we approach that project the way we do all of our others. And so I don't think there was any specific lessons learned there.

Our next question is from Zach Van Everen with TPH.

Maybe when thinking through natural gas demand in the Gulf Coast. So I'm curious how much open capacity you guys have on NGPL Southbound if you guys were able to source more gas to that pipe?

So look, I mean, we are -- once again, you heard we're operating at very high load factors. I mean I think all the low-hanging fruit is pretty much off the table. We're looking at some expandability. You see some reservations that go out there. Clearly, we're working on an opportunity set that's pretty robust in both directions.

As you think about the demand side, you think about power, you think about supply aggregation and you think about movement to get supply to kind of end-use markets, I think the opportunity set there is pretty strong. But as far as specific capacity, I mean, we've got -- there's so many pockets of capacity out there on the EBB. It's out there, if there is any, but I would be surprised if there's any significant capacity in the key areas that you need it.

Got you. That makes sense. And then -- on KinderHawk, it seems like volumes continue to perform well there. Have you brought on a portion of that expansion project and maybe the cadence for the rest of the year, how you plan to bring that capacity on?

Yes. Look, so one, we're operating pretty much at our capabilities at capacity, and we're -- the volumes are there. We're still -- we still haven't brought on the expansion, but we plan on bringing it on as we layer it on through the balance of the year to add an incremental Bcf of processing capacity, and we're on track to do so.

And at the time, I am showing no further questions.

Okay. Thank you all very much.

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.

Okay. Good morning, everybody. My name is JR Weston, one of the midstream analysts here at Raymond James. I'm excited to have David Michels from Kinder Morgan here today.

Really interesting story, a lot of unique kind of growth opportunities here with the asset base that they have, especially on the natural gas side of things, in an interesting cycle here from a natural gas demand perspective with both the U.S. Gulf Coast LNG growth and also a lot of power opportunities and natural gas demand opportunities out there. And so Kinder Morgan is very well positioned to take advantage of some of these trends and translate that into nice growth for their business, one of the large cap kind of diversified blue-chip names in our midstream space. So just really happy to have them here to present with us today.

So I'll turn it over to David now.

All right. Thank you, and thank you all for participating. I'm going to start off with a legal disclaimer before we get going. So this is our forward-looking statement slide. Review this in our SEC filings for risks that could materially affect our expected results. Additionally, I'll be discussing certain non-GAAP measures during the presentation. For a list of non-GAAP measures and reconciliations, see our investor presentation and our website.

Okay. So as was just mentioned, Kinder Morgan is a leading energy infrastructure company. We are one of the largest energy infrastructure companies in the world, and we are the largest in the S&P 500. We move about 40% of all of the natural gas molecules that are produced in the U.S. on a daily basis, including the feed gas that gets liquefied and exported globally. So we are focused on U.S.-owned infrastructure, but we're becoming more and more connected with the global markets given our position in supplying feed gas to these liquefied natural gas facilities that then export to the rest of the world. We own close to 80,000 miles of pipeline, nearly most of that is natural gas. 80,000 miles of pipeline is enough to circle the globe 3x. So it's a lot of gas pipeline, a lot of other product pipeline, and it's a big responsibility that we take very seriously. It also gives us a great competitive advantage when going after new projects, and we'll get into that in a minute. And you can see on the left-hand side of the slide here, 67% of our cash flows come from our natural gas transportation and storage business. So that's what we're going to be spending most of the time today talking about is the natural gas market and some of the really interesting and exciting growth opportunities coming from that market.

Our overall strategy as a company hasn't changed much since Bill Morgan and Rich Kinder founded the company 29 years ago. We focus on assets that are key to the portion of the industry that they are located in. We focus on fee-based, stable cash flowing assets. Even though we're in the energy industry, we're focused on maintaining low exposure to commodity prices directly. So we -- you'll see our cash flow mix in a minute, but it's mostly take-or-pay or fee-based. We have a little bit of commodity price exposure and a lot of that we hedge.

So very stable fee-based cash flows. We prioritize a strong balance sheet and ample liquidity. We use -- we focus on funding our growth capital and our other cash flow needs with organic cash flow generation. And then we have a bias to returning value to our shareholders, and that's primarily done in the form of a dividend, which is well covered and sustainable. Then of course, running our assets in a safe and compliant manner as efficiently as we can is another key part of our overall strategy.

So as I mentioned, the cash flow stability and visibility is very high. This is a very high-quality form of cash flow that we generate. 65% are take-or-pay cash flows, which means we get paid for giving shippers the right to use the capacity in our assets. Whether or not they actually use it, we get paid for that subscription to our assets. So it's kind of like rent. It doesn't matter if you actually stay at that house, you pay the rent.

We have another 5% that's hedged. So for 2026 -- and that 5% hedged is pretty consistent year in, year out. And so for any given year, about 70% of our overall cash flows are fixed. Our revenue is known and it's going to be paid to us. So very high-quality form of cash flow, very stable and visible. Another 26% of our cash flows are from fee-based businesses. And so this is like a toll road. If a car rolls down the toll road, we get paid a fixed fee. Similarly, for us, 26% of our business is fee-based. So highly confident, stable business model.

Now moving back a little bit and looking at the overall industry and some of the trends that are unfolding. The current global natural gas demand is about 410 billion cubic feet a day as of 2024. And this is a Wood EIA forecast, and this forecast shows it going to 541 billion cubic feet a day by 2050. And to put that in context, the U.S. is the largest producer of natural gas today, and we produce about 115 billion cubic feet a day. So between 2024 and 2050, this growth would imply that we need to replace more than all of the United States natural gas production in the next couple of decades, which is a massive amount. And I think that speaks to some of the excitement around the opportunity set that we're going to talk about how this translates into U.S. opportunities. But on a global basis, this is a tremendous amount of additional natural gas demand that is forecast to come to the market.

And how does that translate into the U.S.? This is going back to that liquefied natural gas. We are the exporter of choice for many countries across the world because many of the countries that are driving that natural gas demand that we just talked about don't have adequate or natural resources at all to supply their internal demands. And so they're looking for other countries to supply liquefied natural gas, which is the -- really the only efficient way to transport natural gas internationally. To liquefy it and then put it on ships and then re-gas it when it goes to its host country.

The U.S. is particularly well suited because we have a very robust set of infrastructure, pipelines, storage. Well-known basins, excellent producers. EOG was just in here earlier. They're one of them, excellent producers who have been very efficient and capable at unlocking new sources of reservoir, new sources of molecules to produce. And we also -- and I think in the Iran conflict that's happening right now, I think this is underscored we have a relatively low geopolitical risk in America. So a great partner for many of these countries who are looking for not just the next 5 years of supply, but the next 20 or 30 years of supply, signing up for those types of contracts takes great confidence that you're not going to get interrupted because of geopolitical concerns.

So that's the international part of our business and how it's growing and why it's growing. Domestically, we're also seeing an increase in natural gas demand. So we're not just seeing international natural gas growth driving LNG demand, but we're also seeing domestic demand for natural gas increase. Industrial businesses, a lot of them can't be electrified. And so natural gas is one of their choice feedstocks to supply the catalyst for high heat content type industrial processes.

We're seeing incremental growth from residential and commercial businesses, but we're really primarily seeing a lot of growth from power generation. This was something that we started seeing unfold over the last 3 to 5 years. Population migration, so population moving from parts of the country to other parts of the country, increasing the overall power generation demand for those parts of the country that are attracting new population to them.

Coal to gas conversions, we still have a lot of coal power generation out there, and that is more slowly today under the current regime, but still transitioning from coal to the other dispatchable form of electricity production, which is natural gas because it's -- you've got three dispatchable forms of electric power generation: Nuclear, coal and natural gas.

Nuclear is still a difficult one. still haven't figured that one out completely. I think the small modular reactors might be something on the horizon, but still many, many years away. Coal, as we talked about, is being environmentally and economically phased out. So it leaves us with natural gas. So as these coal facilities are switching over and converting coming to their end of their lives or just being environmentally phased out, they're being most often being replaced with natural gas power generation.

And then, of course, we can't leave this slide without talking a lot about data centers and how much additional power generation is coming from the whole revolution of artificial intelligence and the associated data centers that are required to power them. We're -- I think the total amount of additional demand from that category is still to be seen, but it is definitely incremental to what we had been seeing prior to 2024.

In 2026, some of the recent estimates, and I'm sure everyone has read something about the scale of this investment and the stimulus that it's providing. But in 2026, the five largest hyperscalers are expected to spend over $700 billion in AI investments, which is just incredible. And for us, we're seeing great demand for additional power generation and a lot of that is directly attributable to the power that is being used to fuel these data centers.

We have over 5 Bcf a day of new hookup requests, which gives you a sense for how much new power gen is being requested. Where is that data center capacity being built? Here's a sense for the announced data center capacity by state. And then the red bars are the bars where we have significant infrastructure presence. The gray bars are where we don't.

So the vast majority of these, about 70% of all of this announced data center capacity are in states where we have significant infrastructure capacity to serve that additional load. This represents about 210 gigawatts of power demand. And if they were all gas, that would be 32 billion cubic feet a day of additional natural gas demanded. And again, about 70% of that is in our backyard. So it gives you a sense for the scale and the competitive advantage that our assets have going after some of these data center capacity builds.

Speaking of our competitive advantage, this slide shows you on the right-hand side. So this is bringing it back together. The left-hand side is total natural gas demand for U.S. supplies. Today, as I said, our market is about 115 billion cubic feet a day. And the red line is Kinder Morgan's forecast growing by 26 billion cubic feet a day through 2030. The darker line is Wood Mackenzie's forecast growing a little bit slower, but still growing quite substantially. Both are 20% or low 20% growth over this time frame, which is less than 5 years away now.

And you can see on the right-hand side, the key factor to any peer in this midstream industry to securing additional infrastructure growth projects is, do you have assets nearby that can integrate with or that you can expand off of in order to accommodate this additional load growth? And so the existing miles of pipeline that you have in the ground is very important with regard to securing these additional projects. And you can see here, we have over 58, 000 miles of major interstate pipeline in the U.S.

And so it's much more than our nearest competitor and more than double all but two of our competitors. So we're pretty well positioned to take advantage of this underlying growth trend that we're seeing. Additionally, the existing capacity that we have -- so that was more focused on growth and securing additional projects to meet that additional growth. But the existing capacity that we have is also increasing in value because that capacity is getting full. We'll talk about that in a minute. And you're seeing not just incremental natural gas power -- natural gas demand across the year, but you're seeing it incrementally getting more peaky -- so this is -- these are two lines. One is 2015 average daily demand for natural gas in the U.S. The other one is 2025 average daily demand for natural gas in the U.S.

You could see down in the average temperature range of moderate temperatures, 50 to 70 degrees, the difference between these two bars is, call it, 10, 15 Bcf per day. But as you go to the extreme temperature areas, you could see the differences become closer to 40 billion cubic feet a day. So it's showing you that in cold temperatures and in warm temperatures, the peakiness of the delivery and the capacity needed is higher than kind of the average incremental load over these two periods of time.

So these -- the peak day demand is becoming greater, which means additional storage and pipeline capacity is growing even faster than you would suggest from this page. That 26 Bcf a day doesn't speak to how peak day demand is growing even faster. So that gives us additional growth opportunities, but it also speaks to the value of the existing assets and how important they are.

Okay. And this speaks to, again, kind of the concept that I talked about earlier, the existing capacity becoming more and more valuable. Between 2016 and 2025, the natural gas market in the U.S. grew 44% from 79 Bcf a day to 115 Bcf a day. A lot of that growth was accommodated through existing pipes that had spare capacity on them. And so you didn't see as many growth projects being built as you do in today's market because back then, we had a little bit of spare capacity and today, it's more or less gone on all of the major facilities.

So on the top right part of the page, you can see our 2016 5 pipe average, our 5 largest pipelines that stretch across America, we had a utilization of about 74%. And in 2025, that utilization grew to 90%. That's pretty much full because in the summer and the winter are when we have peak demand and in the shoulder months is when we have a little bit less demand. And so 90% is basically full. You don't really have any spare capacity. And that's playing out. We're seeing it in the values that we're getting for our service, but we're also seeing it in the tenor that our counterparties are willing to sign up for.

You can see in 2016 on those 3 pipelines that we have listed here, the average length of contract was 5 to 6 years. And in 2025, that grew to 7 to 8 years in term. So people are recognizing the value of that capacity and are signing up for longer terms at higher rates, which is all good for infrastructure operators like us.

Okay. So where are we -- that's the backdrop in the industry and where does that leave us today? That leaves us with a very nice robust project backlog. So this is our 5-year committed project backlog, $10 billion in total projects. These are projects that have been sanctioned, approved by our Board. Many of them are under construction. So a high degree of confidence that we are going to be building these and we'll be putting those into service.

Mostly focused on our natural gas area, not a surprise. Strong build multiple here, 5.6x CapEx to EBITDA, very good returns. And again, these are projects, and we'll talk about where some of these are built, but a lot of these are built right in areas that we're very familiar with. So we have a high degree of confidence that we'll be able to construct as well, which is important.

Yes. So this speaks to -- so this slide speaks to the projects and the experience that we have in building large natural gas projects in the U.S. and how successful we've been able to build those and bring them into service. So we spent $5.4 billion on projects from 2021 through 2025, 273 individual projects, and we put them into service pretty much right on line with our expectations.

A little bit of variance on both cost and schedule, but well within a reasonable band of tolerance. So we know how to build these projects. We have a great track record in putting them into service recently. And so we're not expanding our business by entering a new business line or extending ourselves outside of our core competency. We are doing what we do best, which is build natural gas pipelines in the United States.

And here's a list of some of the largest projects that we have signed up right now in that $10 billion of project backlog spend. Just -- I'll just touch on the top 3. South System 4 expansion number one and number three, Mississippi Crossing. You can see on the right-hand side of the page there, they're both taking gas kind of out of the tea corridor there just to the east of Texas over into the Southeast states. That's been a part of the country that's been short on natural gas supply for many years now, and we've gotten to the point now where they've reached critical mass where they needed some real significant incremental capacity to those markets.

And so -- so we're building those two pipelines, which Mississippi Crossing provides liquidity to the South System for expansion to get it all the way over into the Carolina markets, bringing 1.3 billion cubic feet a day of capacity into those markets and our customers are excited about that. They recognize the need for it, and we're actually even starting to talk to them about the next expansion. So a great area to construct pipeline excellent committed commercial contracts with customers that we know very well, they're utility customers, Southern Dominion, Duke, Ogalthorpe,who's a very high creditworthy counterparties as well.

And then the other one is #2, which is it's a smaller pipeline, but it's a substantial build. It's moving from the Katy hub to which is west of Houston over into the Port Arthur market, which is where a lot of the LNG demand is. Katy is where some of the pipelines from the Permian are being delivered into and so that we needed to debottleneck that area between Katy, go up and around over Houston, down into the Port Arthur market in order to get that liquid molecule over into where the end market really begins.

Exciting build. We're already under construction on that one, great counterparty contracts, very good return. 2 billion cubic feet a day of capacity and everything is on track with all three of those major projects. So what's next? Beyond that $10 billion of projects that we've already sanctioned, we're working on the next -- our business development teams aren't working on those anymore. Now they're focused on the next set of projects to backfill those and then to potentially grow even more beyond those.

We have over $10 billion worth of identified specific projects that our business development teams are working on right now, incremental to the ones that we just listed. And the growth drivers behind those incremental new greater than $10 billion of opportunities are similar to the ones that we just talked about. I said, we're already working on potentially adding additional supply projects to the Southeast markets. We're working on debottlenecking within the Texas and Louisiana markets, which is becoming increasingly more important as these LNG facilities continue to come online. You saw how large that LNG market was growing. It's almost doubling between 2024 and 2030. So we're going to see additional debottlenecking efforts required to accommodate that flow.

And then throughout the country, we've got the power generation demand, industrial growth. We've talked about coal conversion all very, very exciting things. Exports to Mexico is another one. Mexico's production is declining. And so delivering additional gas down to Mexico is also another factor of growth that we're focused on. Meanwhile, our financial profile has improved nicely. So we're meeting this time when we have this very robust opportunity set with a balance sheet that's in really good shape. We've been generating some good growth as it is, we've had a cadence in our dividend that's allowed us to have a dividend that is well covered and sustainable. So over the past decade, we've been growing our EPS by about 8% annually while decreasing our leverage by 26% over that same time.

Our leverage target range is between 3.5x and 4.5x. We're at 3.8x right now. So we're a little bit on the low end of that. We're below the midpoint of our leverage target range. So we have a little bit of balance sheet capacity. We're generating cash flow from operations of $6 billion, which means we have about $3 billion annually to spend on these growth investments. So we have a great amount of cash flow internally to support these investments that we're making. We don't have to rely on the external capital markets to any large degree.

And then our dividends, you can see here, we've got this good cadence here where we've been growing. And growing at a little bit of a slower pace relative to our cash flow growth, and that's added to the sustainability of that dividend over this time. You can see we've taken advantage of some of our lower stock prices those light gray bars are share repurchases.

All right. So yes, that kind of brings us to the end. And just to kind of wrap up here, we're very excited about the growth projects that we have. We're very pleased with our recent performance. We're very pleased with the fact that we've got our financial profile in the shape that it's in, in order to meet this current opportunity set driven by the opportunities, driven by the dynamics that we've talked about through this presentation, and we're very optimistic about our future.

So that's it. I think we have a couple of minutes left for questions.

I appreciate that, David. Thank you. Any questions here from the audience?

Maybe one for me here, David. Just, you had there on the slide about the $10 billion of kind of additional growth projects out there. Can you just maybe speak to -- some investors probably understand some of the kind of the secular growth themes that are out there. But just translating that to growth opportunities for the company. How much easier or harder is it getting to kind of convert those project opportunities into real projects that move into your backlog?

Yes. They're always hard. Otherwise, everybody would be doing it. So -- but in some degree, there's greater recognition that existing capacity is full. We talked a little bit about that. And so there's a little bit more urgency to get some of these projects built because they recognize, I think our customers recognize how long it takes to build these things. There's just a standard amount of time to permit and build and get these things constructed. It's not like a digital transformation. There's a lot of physical work has to be done. You cannot bypass.

And so I would say in some regard, it's gotten a little bit more efficient to sign up commercial contracts in current environment relative to where we were 5 years ago, but it's still really tough. And then I would say the other thing that I think I failed to say before is with the $10 billion of committed project backlog that we have today, plus all the projects we're planning to sanction in order to backfill those. If you convert that at the -- at the EBITDA multiple that we talked about earlier, it's a $500-plus million a year of additional EBITDA.

So good single-digit growth on our EBITDA basis, which translates into a high EPS -- high single-digit EPS or low double-digit EPS growth rate, combined with the dividend yield that gets you to a total stock return that's pretty compelling.

[indiscernible]

Yes, that's a great question. That's a really good question. We're focused -- that's one of the big risks, I would say, to our -- to the overall story here because the projects are there, will the equipment and the labor be available for us and for others to build especially with the backdrop of all these data centers that are being developed? There are some components of labor that are going to be competing for those same projects.

Over the past year, we've bid out three of our major projects, and we've talked to our -- the qualified contractors and what kind of capacity they have in the next 2 to 3 years when we'll be building these. So far, there is adequate capacity from major qualified labor contractors. The equipment is getting a little bit longer lead time. compressor units are 2 to 3 years backlog.

And so we're working on some alternatives for us to look at there. But I think that just puts more pressure on us to make sure that our scheduling is appropriate. We're signing up and we're getting committed contracts with our labor contractors and we're signing up for all the long lead time materials well in advance of when we need to put them into service. So far, that's working pretty well, but it is something that we're watching really closely.

And just real quick, David, are you able to -- in some of these situations where you have some cost inflation still pass through some of that and kind of protect that?

That's great. That's a great point. So what we try to do is we try to anticipate the cost escalations associated with the tightness in the market and pass those along in the form of the rate that we're willing to sign up for with our customers. In most cases, we're able to do that pretty well. And a handful of cases we're actually able to put it into the contractual arrangement with our shippers, cost escalations, unforeseen at the time that we sign up the contract with them to sanction the project.

Again, I think that is something that -- that's pretty rare. In the past, we didn't see that as something that the shippers are willing to sign up for. But today, I think because of the fact that capacity is tight and the urgency to get this supply to market is so great, we are seeing more willingness to share and cost overloads.

That's perfect. We're out of time here.

Good afternoon and thank you for standing by, and welcome to the Fourth Quarter 2025 Earnings Results Conference Call. [Operator Instructions] Today's conference is being recorded. If you have any objections, you may disconnect at this time. It is now my pleasure to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 as well as certain non-GAAP financial measures. Before making any investment decisions, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements.

I have only 2 comments before turning the call over to our CEO, Kim Dang and the team. First, we believe our bullish outlook on natural gas demand remains grounded in reality, and we expect to see very strong growth over the rest of this decade and beyond. Now while there are several important drivers of that growth, the largest and most certain driver remains the need for additional LNG feed gas to service both expansions of existing export facilities and new greenfield projects coming online. We now estimate feed gas demand will average 19.8 Bcf per day in 2026, which is an all-time record an increase of 19% from the daily average of 16.6 Bcf per day in 2025. And we see that demand increasing to over 34 Bcf per day by 2030. This astounding growth is enormously beneficial to the midstream sector and especially to companies like Kinder Morgan that have extensive pipeline networks along the Texas, Louisiana Gulf Coast, which is the location of most of the export terminals present and future.

Our throughput agreements for delivery of the feed gas are essentially take-or-pay in nature which gives us great confidence in the resulting cash flow. My second comment is specific to Kinder Morgan. You will hear from Kim and the team that we finished 2025 very strong compared to 2024 and to our budget for 2025. And as you know from our earlier release of the budget for 2026, we expect more good performance this year. Once again, the chief driver of our success in both years is the extraordinary strength of our natural gas assets.

And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. As Rich said, we had a fantastic fourth quarter, producing record results for the quarter and the year, much stronger than we anticipated when we announced our Q3 results.

For the quarter, adjusted EBITDA was up 10% compared to the fourth quarter of last year and adjusted EPS grew 22%. Those are big numbers for a stable midstream business like ours. The biggest driver of the outperformance was natural gas. It had an outstanding quarter and year. Our project backlog has increased by approximately $650 million to $10 billion. We added a little over $900 million in new projects which was offset by $265 million of projects placed in service. The most 2 significant additions are Florida Gas Transmission projects, both supported by long term for contracts. Our backlog multiple remains below 6x, which will drive very nice growth over the next few years. In addition, we're working on greater than $10 billion in project opportunities beyond the backlog. While we won't be successful on all of those, it gives you a sense of the tremendous market opportunity. We believe we will continue to find attractive opportunities for years to come. Wood Mac currently projects the U.S. natural gas market will continue to grow over the longer term, with an incremental 20 Bcf a day of demand growth between 2030 and 2035.

Now a quick update on our 3 largest projects, MSX, South System 4 and Trident. We started construction on Trident last week. And for MSX and South System 4, we received our FERC scheduling order. The FERC anticipates issuing our final certificate by July 31, which is a schedule we requested but ahead of our original expectation. There's still a lot of work ahead, but all 3 projects are on budget and on or ahead of schedule. Another positive last week, S&P upgraded KMI to BBB+. That shows our balance sheet is in great shape.

On the management front, I want to take a moment to recognize Tom Martin, who will retire at the end of this month for his wise counsel and the value he has helped delivered to our shareholders over his 23 years with the company. As we have previously announced, Tom will continue to serve as an adviser to the OTC and the Board, so we'll continue to benefit from his perspective. We're excited to have Dax, who many of you know from his long tenure at the company step into the President's role. I'm looking forward to working with them closely as we continue to execute on our strategy. To sum it up, we had a great quarter and year. We also strengthened our balance sheet and advanced key projects with a $10 billion backlog and tremendous potential beyond that were set up for a very exciting future.

And with that, I'll turn it over to David -- Tom.

Thanks, Kim. I appreciate the kind words. Starting with the natural gas business unit, transport volumes were up 9% in the quarter versus the fourth quarter of 2024, primarily due to increased LNG feed guest deliveries on Tennessee Gas Pipeline. But the full year transport volumes were up 5% over 2024. Natural gas gathering volumes were up 19% in the quarter from the fourth quarter 2024 across all of our G&P assets with the largest impact being from our Haynesville system. Sequentially, total gathering volumes were up 9% and the full year 2025 gathering volumes were up 4% versus 2024.

We experienced a significant ramp-up from our producer customers during the quarter to meet the growing LNG demand. Our Haynesville gathering system, for example, set a daily throughput record of 1.97 Bcf a day on December 24. Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network. For example, we are in various stages of development to potentially serve more than 10 Bcf a day of natural gas demand in the power generation sector.

In our products pipeline segment, refined products volumes were down 2% in the quarter compared to the fourth quarter 2024. For the full year 2025 refined products lines are about equal to '24. Crude and condensate volumes were down 8% in the quarter compared to the fourth quarter of 2024. More than all of that decline is driven by taking double age out of service for the NGL conversion project early in the third quarter of 2025. Excluding HH volumes in both periods, crude and condensate volumes were up 6% in the quarter compared to the fourth quarter of '24. On January 16, 2026, KMI and Phillips 66 announced the start of the second open season on their proposed Western Gateway Pipeline system. Western Gateway Pipeline will connect Midwest and other refinery supply to Phoenix into California with connectivity to Las Vegas, Nevada via KMI's CALNEV Pipeline. The second open season, which concludes on March 31, 2026 is for the remaining pipeline capacity and adds new access to the Los Angeles market via a joint era supported by the planned reversal of one of KMI's existing SFPP lines between Watson and Colton, California.

In addition to expanding the offer destinations, the second open season adds additional origin points to enable supply diversification and optionality for our customers. We believe this project provides an attractive supply alternative for markets in Arizona and California. In our Terminals business segment, our liquids lease capacity remained high at 93%. Market conditions remain supportive of strong rates and the utilization of tanks available for use is 99% at our key hubs on the Houston Ship Channel and at Carteret, New Jersey. Our Jones Act tanker fleet remains exceptionally well contracted, assuming likely options are exercised. Our fleet is 100% leased through 2026, 97% leased through 2027 and 80% leased through 2028. We have opportunistically chartered a significant percentage of our fleet at higher market rates and have an average length of firm contract commitments of more than 3 years. The CO2 segment experienced 1% lower oil production volumes lower NGL volumes and 2% lower CO2 volumes in the quarter versus the fourth quarter of 2024. For the full year 2025 all volumes are about 2% below '24 but finished strong in the quarter to be slightly above our plan for the year.

With that, I'll turn it over to David.

Thank you, Tom. This quarter, we're declaring a quarterly dividend of $0.2925 per share, which is $1.17 per share annualized, up 2% from 2024. For the fourth quarter, we generated net income attributable to KMI of $996 million and EPS of $0.45, 49% and 50% above the fourth quarter of 2024. This quarter's results included a gain on an asset sale which we treat as a certain item. Excluding certain items, our adjusted net income and adjusted EPS still grew very nicely, both 22% above the fourth quarter of 2024.

Our growth was driven by newly placed in service natural gas expansion projects, contributions from our Out River acquisition and continued strong demand for natural gas transport, storage and related services. For the full year 2025, we beat our budget by more than the contributions from our Outrigger acquisition. Outperformance came from our natural gas business, driven by greater value on transport capacity and ancillary services. Our Terminals segment also generated better-than-budgeted contributions. We budgeted to grow adjusted EBITDA by 4% and adjusted EPS by 10% from 2024. We actually grew adjusted EBITDA by 6% and adjusted EPS by 13%. Our 2025 EBITDA and net income were all-time record levels of Kinder Morgan.

Moving on to the balance sheet. As we continue to grow our cash flows and take a disciplined approach to capital allocation, our balance sheet continues to strengthen. Our net debt to adjusted EBITDA ratio improved to 3.8x, down from 3.9x last quarter and down from 4.1x at the end of the first quarter, which was immediately following the acquisition of Outrigger. Since the end of 2024, our net debt has decreased $9 million despite nearly $3 billion of total investments in growth products and the acquisition. So we'll go through a high-level reconciliation. We generated cash flow from operations of $5.92 billion. We've spent -- we've spent $2.6 billion in dividends. We invested $3.15 billion in total CapEx, including growth sustaining and our contributions to joint ventures. We spent approximately $650 million on the Outrigger acquisition. We've received $380 million on divestitures, primarily the EagleHawk sale. And then we had all other items a source of cash of about $100 million. That gets you close to the $9 million decrease in net debt for the year.

The rating agencies have recognized our strengthened financial profile. Last week, S&P upgraded us to BBB positive. Fitch upgraded us to BBB+ during the summer of 2025, and we're on positive outlook by Moody's. So as has already been mentioned, but I'll mention again, 2025 was an exceptionally strong year, a record same year, in fact. We beat our budget and delivered double-digit earnings growth. We grew our backlog from $8.1 billion to $10.0 billion despite placing $1.8 billion of projects into service meaning we added $3.7 billion of projects to the backlog during the year. We improved our balance sheet. We achieved credit rating upgrades and expect meaningful cash flow benefits from tax reform which will generate additional investment capacity. We have very positive momentum heading into 2026.

And with that, I'll turn it back to Kim.

Michelle, if you'll come back on, and we'll take questions.

[Operator Instructions] Our first caller is Julien Dumoulin-Smith with Jefferies.

Look, if I can kick it off more on the data center front. You guys talk about the 70% number with respect to where you have exposure and aligned with data center opportunities. Can you talk a little bit about what you're seeing actively on that front? Obviously, we saw the announcement here, perhaps that seeks out a little bit. But how do you think about that regionally in terms of further data points we should be seeing through the course of the year? And I've got a quick follow-up.

Okay. I'm not exactly sure about the 70%. But if you look at our $10 billion backlog, about 60% of our backlog is associated with power projects. That's not just data center, that's anything associated with power. And if you think about the opportunities on the power side, I think a great example is if you look in the state of Georgia, where Georgia Power, recently, I think the end of November filed a revised IRP. And they're projecting 53 gigawatts of power demand between now and the early 2030s.

And so from a gas perspective, if that was 100% gas, that would be like 10 Bcf a day, roughly, depending on the conversion metrics you use. And we expect that a significant portion of that will be gas, and that's just one utility in one state. And so what we're seeing across our network, whether that's in Georgia or South Carolina or Louisiana or Arkansas or Texas or New Mexico, Colorado, mean we are seeing similar stories just across our network. And the other thing is you look at power demand, we've got a higher power demand growth between 2025 and 2030. Wood Mac has and their most recent estimates increased theirs. And if you look at Wood Mac between 2030 and 2035, they think the power growth, at least in their projections, is greater between 2030 and 2035, than it is in their projections between '25 and '30. So this is something that is driving significant amount of projects. It's also a significant driver of the potential opportunities that we have, and we think will last for a decade.

Excellent. If I can just firm up a little bit more on the SSC 5 setup in timing. What are you looking to move forward on that? How are you thinking about timing? And then even more specifically, if you could speak to, are you thinking about this as being a compression first or looping kind of project initially? And what level of signed utility load would unlock a more formal filing?

Yes, Julien, this is Staples. So look, in terms of timing, we -- we see strong interest in the Southeast, and we continue to work with the customer base in terms of what the final scope looks like, that all depends on final subscription. I do see it more than just compression. I think there could be some more brownfield looping. But once again, it's early. We're working through the demand dynamics with our customer base. We do see opportunity there, and it is competitive. So we will continue to report as we go along. But ultimately, the sign deals, what drives the announcement.

Our next caller is Jackie Caleres with Goldman Sachs.

First, I just wanted to start on the next steps on the Western Gateway following the second open season launch last week. How do you think about allocating capital towards this project versus natural gas opportunity set? And how do those returns compare?

Yes. I mean on every project, we look at based on risk and return. And so I think we have a middle-of-the-road return that we expect and then we vary off that based on the stability, the duration and the creditworthiness of the cash flows. And so it's you've got stronger creditworthy parties and longer cash flows and take-or-pay, then you come off that return down from that return a little bit. And if you have those things are less and you go above that return. All these returns are significantly above our cost of capital. And so I think if we proceed on Western Gateway, we will have long-term shipper contracts there. And I expect those shipper contracts will be largely from creditworthy counterparties. And if not, we would have some credit support. So we don't, at this point, have limited capital. I think we can easily fund this project and do all the natural gas projects that we're talking about. Another point I'd point out on Western Gateway, which is we are contributing assets to that. And so our cash contribution will be less than we're going to -- we're setting up a 50-50 joint venture with P66. It would be less than half of the cost of the overall project because we're contributing value for contributing assets or part of our contribution.

Got it. That's helpful. And then just as a follow-up, leverage ended around 3.8x in the quarter. How do you think about maintaining leverage levels towards the midpoint of your long-term guide of 3.5x to 4.5x range versus leveraging up towards that high end if there are multiple CapEx opportunities?

Well, I'd say right now, what we've said is we're going to spend about $3 billion per year in CapEx. Now that won't be a perfect ground, $3 billion because you just have timing of spend, but roughly $3 billion a year. And we have the ability to flip on that 100% out of cash flow. The other thing I'd point out is that as our $10 billion backlog of projects come online at our debt-to-EBITDA actually declines over time. And so that creates more balance sheet capacity. So for every 0.1x of leverage, that $850 million of capacity. So I think we've got a ton of capacity even without leveraging up closer to the 4.5x. And I don't think we have intention of getting close to that level. So I think we've got plenty of capacities to accommodate the opportunities that we see out there.

Our next caller is Theresa Chen with Barclays.

Kim, I hear you loud and clear on the less than 50% of capital contribution on Western Gateway because you're contributing SSPP. When we think about the net EBITDA impact to Kinder, I'm assuming this project moves forward, how should we quantify the displacement of existing SSPP EBITDA? How much is that contributing currently?

Well, I think 2 things. One, Theresa, I think we're really early. And so we've got to get through the open season, we've got negotiations to do with our partner on the specifics. So I think -- and so I think we've got to finalize costs, et cetera. So I think it's too early to go through that at this point.

Understood. Maybe turning to a different portion of your liquids business. Could you provide an update on the progress of the HH conversion and in light of recent upstream developments in the Bakken and the increasingly challenged near-term outlook for the basin, how are you thinking about the expected NGL throughput and EBITDA contribution from this project?

Sure. I mean the project is going to come on probably late first quarter, early second quarter. and that's Phase 1. And then with respect to the future phases, that's something we continue to work on.

Yes. Theresa, Broadly, though, I mean, we still given the recent pullback, it's just a matter of time. I think our initial phase is well contracted. We see the volumes behind it. These are coming from our plants, and so we have visibility there. So I don't think as far as Phase 1 is concerned, and that is probably on the earlier side of the time frame that Kim gave you in terms of where we come in I think as we look to look to the next phase, we continue to have discussions, positive discussions with our customers. We'll monitor the overall macro situation, and we'll make the investment decision accordingly. That being said, we still have that in front of us.

And I think the other thing is GORs are growing in the Bakken.

Our next caller is Michael Blum with Wells Fargo.

Yes, maybe if I could just ask maybe a different way at the same question to some degree, with Continental Resources effectively I think they're going to stop drilling in the Bakken. I'm wondering if you can talk about, at least for now, can you talk about how meaningful a customer they are, either your current business? Or were they were contemplated to be for HH and if that has an impact on the further expansion?

So yes, if you look at the EBITDA that we get from Bakken or EBDA, it's about 3% of Kinder Morgan or all. Obviously, Continental makes up a piece of that. We don't think that there's going to be any material impact from the Continental news. We think that the impact is very manageable, that's one because it's 3% of our EBITDA. But it's also because volumes came into the year a little stronger than we were expecting. And it's also because they're going to continue to complete wells through August and because they are just one of a number of customers we have out there.

Okay. Great. That makes sense. And then I just wanted to ask, in light of the asset sale that you did here in late 2025. Are there more noncore assets that you're actively looking to sell? And strategically, are there segments or areas of the business that you're more inclined to reduce your exposure to?

Okay. Yes. Let me talk about the EagleHawk sale first. First of all, on that, that's not an asset that we were looking or planning to sell. Our partner approached us because they were selling at least a portion of their interest and based on the price that we could achieve it made sense to sell. It's an 8.5x multiple on a nonoperated minority interest in the GMT asset. And when we looked at the reinvestment opportunity, meaning if we we're buying at the price that we propose to sell and we look at the cash flows, those were going to be below our cost of capital. So and that included taking in into account any tax impact from the sale. So we thought it made sense. It was a good economic decision to sell that asset and recycle that capital. And so that's generally the way that we have been approaching sales of assets, which has been more opportunistic. As we say, our assets are for sale every day at the right price. And so we want to make good economic decisions about that. We like the portfolio of assets that we have today, 60 -- it's 2/3 natural gas and 26% is product pipelines and terminals, very similar pipeline and storage business. So the 7% is CO2, which is a little bit different, but we get great returns on that business, and we have an expertise that a lot of people don't have. So I think we're very comfortable with the suite of assets that we have, and this was just an opportunistic sale that made sense.

Our next caller is Jeremy Tonet with JPMorgan.

I was just curious for your thoughts, I guess, industry at large and what opportunities it could present to you down the road just if we think about Waha egress. One, we have some pretty cold weather coming up in during Yuri, that presented opportunities for Kinder last fall round. So just wondering if you could share any thoughts there.

Well, look, we as always here, when we look at the footprint, given our footprint, we're able to leverage basis dislocations that occurred. First and foremost, we want to serve our customers. And then to the extent that these opportunities present themselves, we've been taking a little more of a proprietary view on certain things in certain areas, strategically, small amounts. And so to the extent that, that presents itself, we'll be able to leverage that.

Yes. But I don't think this storm is not a yeary.

It's not a yeary.

I mean it's much shorter in duration and it's not going to be as significant. So...

Understood. It seems like there might be another one on a heals. So we'll see what happens this winter again.

Generally, what I would say is that the gas transportation market is very tight. And so whenever you see dislocations in supplier demand in and around our assets, that is going to present opportunities for us. And that's part of what you saw in the fourth quarter of this year.

Yes. And the key component of that is storage for us, and we have a significant storage portfolio that will allow us to leverage some of that to the extent that it presents itself.

Got it. And then just wanted to dial in on NGPL a little bit here, hearing more data center-driven opportunities in the Midwest, coal to gas switching as well, some of the other nat gas pipeline operators are seeing a lot of activity there. I'm just wondering if you could talk about what that could mean for Kinder for NGPL?

Yes. So look, we've -- we're quite a bit of -- there's significant discussions. You've been seeing some of the EBV postings we've been making out there. we've got interest along the pipeline in terms of not only just from power customers but also from organic markets that are trying to grow -- still early on some of these projects. We've got some binding commitments that we're looking to convert into full flood FID projects as these develop, we'll bring them. But I mean, when you think about the corridor itself, when we see a concentration up in the market area. We have some in the producing regions where folks are looking to site themselves. And so I think the opportunity set is there. It's just, once again, we're in this mode where folks are looking -- there's -- it's a competitive landscape, and so we want to make sure we secure the returns that we need to progress the projects to FID.

Our next caller is Jean Ann Salisbury with Bank of America.

You said in the prepared comments that MSX could be in service a couple of quarters early. I think is there any read across to a faster permitting process across the board? Or was that project specific?

No. I mean I think a couple of things on these projects. One is 871 is gone, and that happened, I don't know, 6 or 9 months ago. and basically required us to wait 5 months between when we got our FERC certificates on when we could start construction. So that's gone. And then the FERC has acted within -- is going to act within roughly 1 year on our filing. And so previously, we've been seeing that take a little bit longer than that on big projects. And so the fact that the FERC process only took 12 months and we don't have 71 is speeding up our in-service on MSX from called the fourth quarter of '28 to the second quarter of '28.

Great. That's a clear. And then one of your peers took an equity stake in a LNG terminal a few months ago. Is that something that KMI is actively looking at or would have interest in, especially, I guess, if you could back to back it with another counterparty to make it take or pay equivalent?

You make it. Well, I'll say a couple of things on that. Generally, what we've seen on the LNG front is the returns haven't been where we needed them to be to make those investments. And it's not something that we are accustomed to building. We do a small one, obviously, at Elba, but that was a relatively small facility. And so I think in general, what you should expect from us is that we are kind of sticking to our knitting, we're staying in our lane. We are serving those that LNG demand through our pipelines. And right now, we serve 40% of that demand, as Rich said, that demand is expected to grow significantly, and we expect to get our fair share of that future demand, and that's driving very nice project opportunities for us. So I'm not saying we would never step out. It's just there hasn't been the opportunity where we thought the risk return profile was appropriate. And we haven't wanted to build these on our own.

I think another thing we like on a risk-return basis is the fact that both on the LNG terminal side for feed gas and on the service to -- for electric generation purposes, we have, in general, take-or-pay contracts with utility grade investment-grade utilities. And that, we think, is a very good way to look at the risk that we are taking. And we think that minimizes any risk that we have as opposed to contracting directly with AI developers, for example.

Our next call is Keith Stanley with Wolfe Research.

You updated the messaging on CapEx to at least $3 billion a year of growth CapEx for the next few years, up from $2.5 billion wanted to clarify, is that solely based on the sanctioned project backlog today? So if you keep FID-ing new projects and the backlog grows, CapEx could be above $3 billion a year for the next few years? Or is that already reflecting your best estimate over the next few years?

I'd say it's largely based on the $10 billion approved project backlog, but there is some view there is a small portion that is based on getting some of the $10 billion in the -- in the opportunity set. So -- and look, I think that we updated it from $2.5 billion to $3 billion given the $10 billion given we continue to add to the backlog even after putting projects in service. So this year, when we were putting all those projects in service at the beginning of the year, we thought it might come down. It's continued to increase natural gas demand, we continue to see it grow between '25 and '30, but also beyond that. And so there may be the opportunity to extend that further, but we're not ready to do that or make it higher, but we're not ready to do that at this point in time.

Got it. Second question, just wanted to follow up on the earlier one on Mississippi Crossing. So if you're 6 months early on that project and on potentially on some of the other bigger ones given the regulatory environment. Would your contracts kick in and you'd have pretty close to a full financial contribution right away at that earlier date? Or is that not the case?

It's a project-by-project analysis. In this case, the answer is no, the customers don't have to take it at that point in time. Can, I mean, they can elect to take it, but they don't have to. And I would say that being early on the regulatory front does not directly translate into day for day on the in-service. It's going to depend on the projects because once you move back that regulatory, once you get sooner approval from a regulatory perspective, you have to think about when you're getting pipe and when you're getting compression. And so for example, we haven't seen that translate into much of an earlier date on South system at this point in time. So it's project by project. But if our customers don't want that capacity, it will be available for us to use during that time.

And given the macro environment, Keith, I mean, you just think about the demand profiles that are coming our way, it's just -- you look at that as an opportunity to sell in the secondary markets.

Our next call is Manav Gupta with UBS.

Firstly, congrats on all the upgrades from rating agencies reflects the strong quality of the management and execution. I wanted to ask you about the Florida gas transmission projects, both the projects. How did this come about? Can you give us more details? And then the last one year, what you have seen is you announced the project and then end up upsizing it. So if you could talk about the possibility of some upsizing here for these projects?

So Manav, this is Staples. So just in terms of the project itself, as you know, we're not the operator. energy transfer as the operator. So let them talk about how it came about on the call. We've been working with them closely. Thematically, it's the same things we've been talking about in the Southeast. We see that as a growth area, just broadly. And this is just another example of us getting incremental infrastructure to an area where there is significant growth. There's also a resiliency component there with the 2 projects. We think it makes sense in terms of whether or not the project gets upsized, but we're in the process of having an open season right now. The open season closes here, I think Fed fit if I'm not mistaken. And based on the interest there, is it possible to upsize Yes, if there's a demand for it.

Yes. I'd say both those projects are backed by long-term contracts with creditworthy counterparties. And so I mean, they are right down... .

Perfect. And my quick follow-up here is, at the start of the call, you mentioned that the 4Q turned out to be stronger than what you thought when you announced your 3Q results. So help us understand some of those tailwinds which help you drive the beat in 4Q? And are those still persistent out there? So should 1Q also turn out pretty strong, if you could talk about that.

Sure. So I mean, it was across the gas network. So it was our trust. It was our interstate pipes and our gathering assets. And so both as we said before, when you [Technical Difficulty].

This is the operator, please standby. And speakers, please go ahead. The next question comes from Jason Gabel.

It's Jason Gabelman from TD Cowen. Hopefully, the storm hasn't have you too hard down there. Maybe to start and to help everyone out, maybe we could just replay Manav's question because I was interested in the answer to it. I didn't quite hear. So just wondering what drove the earnings upside on the natural gas segment in 4Q. It sounded like some of it was driven by pull from LNG plants. So did some of these plants start up earlier than you had expected in the plan? Or were there other factors at play?

I mean, it was -- look, it was across the entire gas business. So it was a lot in our Texas and trust at market. It was in the Eagle Ford and the Haynesville on our gathering assets. And then it was also on the interstate markets more so in the Northeast than other areas. And so it's a function of having a very tight pipeline and storage network and that's going to create opportunities when you have supply or demand dislocations that could be leather, that could be LNG coming on or off to be a variety of factors, but that leads to volatility and upside for us. And there is the potential for that to happen again in 2026.

Great. And my follow-up maybe staying on the topic of LNG. It seems like the market is facing this upcoming global supply glut and maybe you get a bit of a slowdown in the pace of new liquefaction project sanctions here in the U.S. Gulf Coast. So just wondering how much of that project backlog if any, is tied to servicing incremental projects? And I guess it's not the project backlog. It is the shadow project backlog and projects -- LNG projects that are associated with that shadow backlog?

Yes. So a couple of things. I'd reiterate the point Rich made a minute ago, which is -- the -- we have long-term take-or-pay contracts with these LNG facilities. And so those typically are 20- to 25-year contracts, and they pay whether they use that capacity or not. In our current backlog, about 12% of the $10 billion actual crude project backlog -- 12% of the shadow backlog is associated with LNG. So it's not a huge percentage. I think a lot of the shadow backlog, again, is going to be more on the power front. But the other thing I'd say is that when you look at these LNG projects, it's not always about adding a new facility. A lot of times, it's about an existing facility has some capacity and they want to reach further back to get more competitive supply. So to have incremental project, you don't have to have a new facility come online. It could be a need from an existing facility to try to get more competitive supply.

And at this time, we are showing no further questions.

Okay. Thank you, everybody.

Thank you. Have a good day.

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.

All right. This is the session for Kinder Morgan. To my left, I've got Kim Dang, CEO; and Dax Sanders to her left, yes. So thank you all for being here. Appreciate it.

Yes, good to be here, Michael.

First of all, if you don't mind, could you just close the door in the back. Thank you. So put out the guidance last night. So I figured maybe just start with that, just talk through it, and then maybe I'll have a question or two on that.

Sure. So we put out a guidance, which shows a 4% growth in EBITDA from 2025 to 2026. It shows 8% growth in earnings. It shows us ending the year -- next year at 30.8x debt to EBITDA on the balance sheet well -- or at the lower end of our 3.5 to 4.5x range. And it shows $3.4 billion of expansion CapEx. The other thing we did was we raised our expansion CapEx guide. We used to talk about approximately $2.5 billion per year, and now we're talking about over $3 billion per year for the next few years, and that's just a function of the project opportunities that we've continued to add to the backlog as well as the timing of that spend. And so we think a fantastic opportunity in the midstream space right now, getting nice growth in EBITDA and earnings and lots of opportunities for economic investment.

Great. And I should have set up front, if anyone has questions, just raise your hand, we'll run a mic to you, and just -- at any time, just raise your hand and ask a question, just feel free to interrupt me. Yes. So I guess at a high level, like you said, it's a pretty exciting time in the industry and certainly for the company. It seems like you're in the right place at the right time. So you've had a really significant increase in the backlog for the last few years, almost all of that gas pipeline investments. I guess my first question is, and maybe you kind of answered it already is, what inning do you think we're in here? Like like how long do you see the runway for growth and projects and investment opportunities? And do you see any risk to that long term?

Sure. So I'll start with the existing backlog of projects. So these are projects that we have contracted and our Board approved. So that's $9.3 billion is our current backlog of approved expansion projects. That's up from, as you mentioned, substantially from two years ago. Two years ago, that number was $3 billion. So that $9.3 billion is going to generate nice growth in EBITDA for us. As you said, 90% of that is associated with natural gas, and it's coming at less than a 6x EBITDA multiple. All those projects, again, Board approved and contracted with customers. So that will lead to nice growth. But beyond that, we have a huge set of opportunities that we're working on. And when we go back and we look at that set of opportunities that we're working on that's sort of beyond the backlog, we went back, and we looked at it when the backlog was $3 billion. And then obviously, we know what it is now, and that opportunity set hasn't changed. It hasn't gotten any smaller from when the backlog was $3 billion. So we feel like we've got really nice continued opportunity in the natural gas space, that's being driven by the 20% plus growth in natural gas -- in the natural gas demand that we expect between the end of 2024 and 2030. And it's going to be between 22 and 28 Bcf a day, and 22 is WoodMac's number, which is a third party, 28 is Kinder Morgan's internal number. And that's primarily being driven by export LNG and power as well as a little bit of Rails Com and exports to Mexico. So just a fantastic time to be in this space, seeing lots of opportunities to expand our existing asset base and serve the market.

So maybe just to follow up on that. On the last call, you made a few interesting comments to frame that. You talked about evaluating more than 10 Bcf of natural gas projects tied to the power gen sector. And then you also talked about $10 billion of potential projects, I think, mostly tied to natural gas. So can you bucket those, or is there a way to think about what those -- a little more color on what those are?

So yes, the opportunities beyond the $9.3 billion backlog is the over $10 billion of potential projects. Now say this, some of those projects won't happen, and we won't win every one, but it's a huge set of opportunities to be working on. I'd say that the $10 billion looks kind of like the $9.3 billion backlog. It's more of the same in terms of -- it is focused on natural gas. So it is almost all natural gas. It is driven by the same demand drivers and supply drivers that we see in the $9.3 billion. So it is power demand, it's export LNG. It is driven -- we have a gathering position in the Haynesville, it's a potential expansion of our Haynesville position. So it's all the same drivers. And I would say in terms of size and scope of projects within that, it looks pretty similar. You have a couple, a few that are big projects, and then you have a lot of singles and doubles in there. And so -- and I'd say, is largely across the Southern United States as you go from Arizona to Florida. But we do have some pipes go in the Northeast. So we have some potential developments there and then some on NGPL that goes into Chicago, a little bit in Colorado, but it is substantially across the Southern United States. So I'm confident we'll get -- we will be able to take some of these projects and ultimately be able to add them to the backlog over time. Now timing is a little bit harder to predict, but the need is there, and we've got a great position to work from with our existing asset base to deliver value to our customers.

So maybe if I push that a little bit. I guess a multipart question here, but some of your potential customers have put some stuff out there. So Southern -- SNG, they sort of intimated that they could spend another $1 billion on another SNG expansion. You've already done one as we know. So curious if you can talk about that at all. And then -- and there's also been Dominion has listed you as a gas supplier for our proposed 2.2 gigawatt plant that I think would be in service in like 2032. So either speak to those projects specifically if you can. But if not, maybe if you could talk about like the process, how this happens, what's the conversation with the customers? How does the project get from development to FID?

Sure. Sure. So the first expansion of our Southern Natural Gas asset, which is a gas pipeline that moves gas into primarily Alabama and Georgia. It's a $3 billion [indiscernible] project. Our partner is Southern. We have some expansion on existing systems as well. And so our share of that project is, I think, approximately $1.8 billion. So a big project for us. I think things are going pretty well, expect a FERC certificate probably next summer, and then we'll start construction. So fully contracted pipe and comes in service mainly in 2029. So -- but I think Southern's continue to see incremental demand in the Southeast. Georgia Power, which is one of Southern's subsidiaries, they filed an amended IRP at the end of November, and they were showing 53,500 megawatts of power demand between now and the 2030s. And so if you look at that, and this is just a rough -- when you convert that to gas demand, just rough math, because there's a whole bunch of assumptions that go in here. That's going to be probably over 10 Bcf a day of gas demand. Now not all of that will be gas, right? And some of that -- a small portion of that is being served by the SS4 expansion. But even if you adjust for those two factors, that's still a huge amount of incremental demand in that market. And that's one utility in one state. You're seeing similar things. You mentioned South Carolina and Dominion and Santee Cooper that power plant that you mentioned there is being served by our Bridge project, which is about a $425 million project that is in our $9.3 billion project backlog, and it comes online in 2030. That's about 325 dekatherms a day, but that pipeline is easily expandable. And so like what we see with Georgia Power and Alabama in Georgia, we expect that those South Carolina utilities will probably add additional demand -- power demand over time and our pipeline -- our bridge pipeline is easily expandable to meet that demand. So what we're seeing in Georgia and South Carolina, that's just a microcosm of what we're seeing across the entire Southern United States and in pockets elsewhere that we -- where we have existing capacity.

So maybe just a follow up on the Georgia example. So 10 Bcf, let's cut that in half, let's just say, make it easy 5 Bcf. I guess a couple of questions. One, how many competing pipelines are you, who are you competing with there for that business, and what are the limitations of what LNG can do in terms of ability to expand further, like is that another factor?

So SNG has got a great position in Georgia and Alabama. And it's got two legs to that pipeline that goes through those states. So it's got a great position to compete from. In the northern part of the state, Transco does go through the northern part of the state. And so there is some competing pipeline infrastructure. And so I'm not saying that we will get 100% of, in your example, the 5 Bcf. I mean it's going to depend on exactly where the power plants are sited, et cetera. And so there's probably going to be that some of the competition gets. But in my mind, in those kind of numbers, there's plenty of gravy to go around, plenty of food to go around. So I think it will -- there's a nice opportunity for a South System 5 Expansion.

Great. I appreciate that. What about -- maybe we turn to Arizona for a minute. So obviously, you had a product that you're developing. It didn't happen fine, but you've said that you still see opportunities to invest in Arizona. So I wonder if you can just elaborate on what that means?

Yes. So two, there's opportunities on the natural gas side and then there's opportunities on the product side actually in Arizona. And so -- let me talk about natural gas real quick, and then I'm going to let Dax talk about the products opportunities. For those of you that don't know Dax, Dax has been with Kinder Morgan for as long as I have. He most recently ran our Products Pipeline business unit and is now the incoming President for Kinder Morgan. So Tom Martin will retire in January, and Dax will take that position. So on the natural gas side, yes, there are more opportunities, just like I said, in the Southeast where Transco will have probably opportunities on some of the power plants depending on exactly where those power plants are, we've got an existing system and that goes out to -- that goes through New Mexico and out to Arizona. And so there's going to be opportunities on power plants in Mexico and other places in Arizona that may not be Phoenix, which is where the new pipeline that competitors scheduled to build is going. There's other places, and there's coal conversions and other places that will need power in Phoenix and Arizona. So I think we're well positioned to compete for some of those opportunities. And so we do see additional opportunities in those states on the natural gas side. And then on the product side, I'll let Dax speaks to that opportunity.

Yes. We got an open season going out there right now in the desert Southwest that actually has brought a lot of interest to a market that's been incredibly boring for probably the last 50 years. But the project, we partnered with P 66, and we're looking at expanding our East line system from El Paso into Phoenix. And also as part of the JV, we would build a line from Borger into El Paso that would bring 2 barrels from Borger as well as Wood River. So the project also would reverse the gold line, which connects Wood River to Borger, would reverse that line, bringing barrels again from PADD 2, Wood River into Borger barrels down to El Paso all the way across the desert into Phoenix. And then our existing system brings barrels from El Paso into Phoenix as well as West Coast PADD 5 barrels from California into Phoenix. That market's about 250,000 barrels a day. Our project would also reverse our West line, so it would clear barrels that are coming into Phoenix -- out of Phoenix and move them into the Southern California basin. So we've got an open season out right now with P 66, that closes in the next 1.5 weeks, couple of weeks. We haven't put a lot of details out because there is a competing project out there, and it's a very, very competitive market. So -- but it's something we're excited about. And hopefully, that will come together. We're pretty enthusiastic about it.

And the dynamic driving that is just the shutdown of refineries in the California market. And so the California refineries right now serve the Phoenix market, Tucson market to some extent and also the Nevada market, specifically Las Vegas and Reno. And so that's what's basically producing that opportunity.

Just one follow-up on that, on the refined products pipeline project. What's the timing? Just can you just lay out the timing of that?

Yes. So the open season closes in the next kind of call it, 1.5 weeks to 2 weeks. I think we'll see what the open season produces, and then we'll get together with our partner. Our expectation is if we have a project that we would probably look to FID sometime in the first quarter.

So I think I know the answer to this question, but I'd like to ask it every now and then. Just on the behind-the-meter power market, which Williams has obviously very -- been very front-footed in. None of the other pipeline companies seem to have really done that. So I'm pretty sure that you're not interested in that. I think I know that. But you had talked about potentially creating some kind of partner structure with other players and then having like a package effectively to deliver to a potential developer or hyperscaler. Can you just talk about where that stands today, if I describe that correctly?

Yes, sure. So you're right on behind-the-meter in terms of building power plants, that's not our cup of tea. That's not our business. And so we've done some new businesses in the past. And it's hard first time that you're doing something and doesn't always go as smoothly as you would like. And so that's why we've passed on that opportunity. But we're seeing huge power demand and opportunities to serve power demand. That includes data centers. Sometimes -- a lot of times, what we've seen early on is it's been the regulated utilities, that are building the power plant. So -- and then the data center demand is contract -- or the data centers, et cetera, hyperscalers are contracting with the regulated utilities. And so we're serving the regulated utilities, which is a great model. We did have a sort of consortium that we put together, bring a power plant developer and a data center developer and us. We haven't found that, that's really necessary to get the gas supply to the power plant or to the data center. We haven't found that, that's been necessary to compete. And so we just -- that's still something that we could do. But in general, we found that we are getting opportunities without having to complicate the task.

Got it. Maybe just last question I think I have on gas is gas storage. So maybe you can -- maybe just start by describing your current footprint? And then; a, do you see just natural uplift in EBITDA as contracts roll, like where is your contracts versus rates today? And then do you see expansion opportunities around your gas storage assets as it relates to everything else we've been talking about.

Sure. So our storage footprint is 700 Bcf, so pretty substantial storage portfolio. And about 75% of that is regulated, meaning the rates that we charge are set by the FERC in conjunction with our shippers generally. And about 25% of it is unregulated. So on the unregulated market, it's just basically market-based rates. You're competing with other people have storage to set those rates. Those rates have increased substantially over the last couple of years. And so typically, it depends, but those storage contracts are 3-ish years. And so you're marking that portfolio to market every three years. And they don't roll -- it doesn't roll ratably. And so -- but you can think about 1/3 of that rolling every year, give or take. So -- but yes, I mean, storage has been great. We've done a couple of expansions. We completed one last year, which was a 6 Bcf expansion on storage facility in Texas. We are doing another store, 10 Bcf expansion of a facility. We actually just got the FERC permit on within the last week on NGPL, which is in East Texas. And then we recently just had an open season for a storage facility that we own in the Southeast and got very good demand on that open season. And right now, in the process of working to put together a project. Brownfield, as you can see from the projects we've done, brownfield development, which just expanding existing storage facilities' works. You can get the rates you need and the contract duration that you need. I'd say in terms of greenfield, that's a little more difficult because generally, to do a greenfield project, to get the rates to where you need them to be, you've got to have five or six or seven customers sometimes because of the size, the scale and scope of that facility. And so getting that number of shippers to sign 10-plus year, 10- or 10-plus year contracts is not there yet. The rates are there, but -- and so -- but I think we're getting close -- a lot closer on the greenfield side.

Okay. I lied, I had another gas question. Sorry. So there's been a lot of -- in the market, like the stock market, there's been a lot of angst about the AI bubble, that's kind of vacillating here and there. I'm wondering if in your discussions with potential customers for incremental gas supply into these power projects, are you seeing any of that hesitation, or is any of that kind of angst around this AI bubble manifesting in your conversations?

Well, I think by the time they're getting to the gas supply piece of it, a lot of time -- I mean, yes, we're having conversations early on, but I think that -- we try to push away the projects that we don't think are going to happen so we can focus on the projects that we think are more likely. And then as we focus on the projects that we think are more likely then we're thinking about, okay, what's the credit here. And that's why you heard me say earlier, doing it with regulated utilities is a nice place to be to have that credit on the other end of the gas supply contract. To the extent that you don't have a regulated utility on the other end, there could be -- we're going to look to determine whether we think collateral is necessary and a lot of times, we do. And so we'll get some form of collateral to help us mitigate cost to make sure we're not going to be out of pot depending on what that credit is. I mean we might require as much as the entire project cost to be backed by an LC or something. That would be someone who doesn't have very good credit, someone that's got better credit than you'd have, but not utility-like credit, then you'd have -- you'd be somewhere in between the two. So that's generally how we think about it, make sure that we have the right credit. So that if you do have a bubble in this market that we've tried to pick the winners, and that where we have a little bit more -- took a little bit more risk. We get higher returns and have a collateral.

Okay. Maybe just a related question on the regulatory and the permitting environment. So I guess the question would be this administration came in sort of touting that they're going to have a better more industry-friendly environment. So I'm curious if you're actually seeing that, or how the -- how do you think they've done so far in terms of making it easier for you to do business to -- yes, permitting as well, which obviously...

So I think they've done a good job so far. I think there's more to do. That's what I'd say. So let me tell you about where I think they've done a good job. So the core of engineers has been very quick on response and permitting, et cetera. And that is a change from what we've seen in the past, their engagement and their responsiveness, and they're issuing a permit is just much faster. On the FERC side, which any time we build an interstate natural gas pipeline of any significant size, we have to have a FERC permit. And we've seen some improvement on the FERC side. The most substantial improvement was they basically retracted what was called 871, which basically was a 5-month period from when they permitted your project to when they would let you start building to give landowners time to appeal and them to resolve those, so they -- which is something that they had only put into effect 2 or 3 years before, and it is just elongated time lines. So they have rescinded that. So that gives us immediate five months benefit. On our big projects, they have said that they're going to issue our permit in 12 months. They've committed to that. That's the schedule that they put out there. And so on some large projects, prior to that, it was taking longer than 12 months. And so them committing to 12 months, I think, is a win. Where we would like to see more is we would like to see that 12 month, and this is on big projects, right? If you're doing a smaller project, it doesn't take 12 months to get a project -- to get a permit. But we'd like to see them compress that 12-month time line more. That being said, we want to make sure that the permits they're issuing are durable. So we don't want them to issue just -- take this to the extreme in one day because then they wouldn't have done the work necessary for that permit to be durable if it was challenged in court. So -- but we think that there is a reasonable basis to have durable permits and be less than 12 months to get there. So we'd like to see some incremental improvements there. And we're actually -- we're working with the FERC to propose some of those changes. So they -- the other thing they did was they took up some of the limits where you don't have to file a permit, or where you can file a very modified permit in terms of the cost of the project. So they -- in one case, it's 1.5x now. So they increase those limits. And so that was -- that's a win as well. So I think we've seen some good progress so far, but would like to see more. And I think at some point that regulatory ends up not being the gating item, you're going to get into the supply chain being the gating item. And in some cases, depending on the project, we're getting close to that. But in other cases, I think there's still room on the regulatory side.

Could you expand on last comment about the supply chain? Where are you seeing the potential...

So on the supply chain, I think the biggest issue is going to be on compression, really. And on our big projects that are in our backlog, we've secured our compression and no concerns. And I think at this point, I feel like we're going to hit our dates there in terms of projected in-service dates. I think it's on new projects, where it can take a longer time. On the interstate projects, again, with the current regulatory environment, generally not a concern, but if you're doing an unregulated project, that can elongate those times. We're seeing some capacity added in the market -- well, not added yet, but going to be added in the future, but it will take time to get that capacity on, get it running smoothly. So I don't think we're going to get help there for maybe another year or so.

Okay. Just one more follow-up on that. I mean there's -- obviously, you and many of your competitors are all pursuing a lot of expansion projects. Do you foresee at some point that labor becomes a constraint, or do you feel like that?

We haven't seen it to date. That doesn't mean we won't see it. I mean we're going to -- we're constantly on the lookout for that. But we've been engaging with a lot of contractors on the big three projects, MSX and South System 4 and Trident, which are $5.3 billion of the $9.3 billion backlog. And to date, we haven't -- those things seem to be about on budget. Now we're not fully done there in terms of getting those contracts, but the preliminary -- we'll try that or essentially done. But on South System 4, for example, on the preliminary numbers we've seen there, it's been within budget.

Maybe if I just turn to capital return for a second. So obviously, you just announced your dividend and your guidance for '26. So that is what it is. But I'm wondering just holistically, your rate of EBITDA and cash flow growth is accelerating. You're going to -- at least on our math, you're going to be growing EBITDA in the next bunch of years faster than the roughly 2% increase in the dividend. So I guess the question is, do you see -- would you consider, or would you think about accelerating cash return as your cash growth improves and what form would that come in? Is that -- could it be a faster dividend growth rate? Is there buybacks? Is there -- or maybe you want to keep that capital, so just curious how you're thinking about?

Sure. Sure. So we've been, again, growing our dividend at about $0.02 the last few years. And that's really just a function of the opportunity set that we have out there on the capital side. And as we said to the beginning of this session, we just raised our expected CapEx guidance for the next couple of years from $2.5 billion -- around $2.5 billion per year to over $3 billion. And so the reason that we've been conservative, I would say, in our dividend growth rate is to preserve that capital and preserve flexibility for all the opportunities that we're seeing out there. And so I think on the other side of some of the CapEx, the over $3 billion. I think it's a -- and then you'll start seeing projects come in service, then it probably makes sense to look at a faster growth than the dividend rate. But I think right now and for the next few years, I think the strategy that we have is the right one.

Okay. And I'll squeeze one more in here...

And then the other thing I'd say in terms of buybacks, that's just going to be opportunistic. And our balance sheet, as I talked about a few minutes ago, 3.8x debt to EBITDA, the high end of our range is 4.5x. Every 0.1x is $850 million. I don't foresee us taking our balance sheet up to 4.5x that we like having that flexibility. But if there were -- if we saw opportunities for share repurchase, we have some capacity there to do that.

So maybe just to round it out in the last -- well, we are over a bit, but it's fine. Just M&A, obviously, there's a lot in your plate organically. So it just feels like maybe you don't need to do anything, but just curious what the landscape looks like? Is it even on the table, or do you just feel like, you've so much internally that it has to be pretty special.

Okay. So I'll say a couple of things, and then I'll let Dax add to it because Dax ran corporate development for a number of years at Kinder Morgan. So look, I think that's part of the reason to keep your -- to keep the capacity on your balance sheet so that when we see opportunities, we can take advantage of them. M&A is opportunistic. You can't schedule it the way you look at an expansion project and, you've got a year down 1 or 2 years down the road, you're going to bring these things in service. I mean those things arise and got to have the flexibility to be able to take advantage of that. We think our balance sheet gives us that. And if you look what we've done in the last couple of years, we did a tuck-in acquisition the beginning of this year in the Highland, we did a tuck-in acquisition in Texas at the beginning of '24. And then I think in '22, I think it was, we did stagecoach versus storage acquisition in the Northeast. So we've been finding opportunities and that $850 million per point 1 turn, that's just straight adding debt. If you're doing an acquisition, and you're adding EBITDA as well, then you've got more capacity or less use of the balance sheet, however you want to think about it. So I think we're in a position where when we see opportunities, we can take advantage of them.

Yes. No, I totally agree. I mean we like M&A. Our company was built on M&A over a 30-year period of time, but you got to be incredibly opportunistic about it. It's very difficult to predict when the opportunities come about. You've got to align economics, social issues, people's willingness to part with stuff at a reasonable price. You don't -- it's generally not a good idea to lock in on something you want and chase it at all costs. That's how you end up with bad deals. So we tend to -- any process that happens in our space, we're generally included in. We generally see what's going on. And so we generally sit back and wait to see what happens and participate when it makes sense. And with respect to selling stuff, people ask about that pretty frequently. We're we're a willing seller at everything we own every day at the right price, and that's a true statement. That's not just a line. But you generally have to have somebody who has a different thesis on an asset, then you do and a lot of people, a lot of people -- there are a lot of introductory conversations about a potential transaction that as time passes, and it gets closer to time to actually kind of check those don't necessarily come to fruition. So we are working on both ends of that all the time. And we're only going to do things when they make sense.

Great. Well, thank you very much for the time this morning. Appreciate it.

Thank you.

Good afternoon, and thank you for standing by. Welcome to the Third Quarter 2025 Earnings Results Conference Call. [Operator Instructions] Today's conference is being recorded. If you have any objections, you may disconnect at this time. It is now my pleasure to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan.

Thank you, Michelle. As usual, before we begin, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities and Exchange Act of 1934 and as well as certain non-GAAP financial measures. Before making any investment decision, we strongly encourage you to read our full disclosure on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. I think we all recognize the positives and negatives of publicly traded companies One of the biggest pitfalls is the undue concentration on quarter-to-quarter or even day-to-day issues, many of which are relatively inconsequential in terms of the long-term success of the enterprise. With that in mind, I thought I'd take this opportunity to stress 2 important substantive factors that will impact the future of Kinder market. The natural gas story and the long-term strategy of our company. Obviously, the 2 are intimately related.

On the natural gas demand front, there are 2 huge drivers. The first is the continued rapid growth in LNG feed gas demand driven by the enormous expansion of export facilities, primarily along the Gulf Coast. While industry experts differ somewhat, there's a pretty broad consensus that demand will at least double between 2024 and 2030. In fact, S&P's commodity insights recently estimated that increased at 130%, which implies a demand of 31 to 32 Bcf a day in 2030.

As an example of this growing demand, 6 LNG projects have reached FID so far in 2025. Feed gas demand for those facilities alone when completed will be 9 Bcf per day. Now there's more variance in assessing the impact of the second driver, which is the increasing demand for electricity, primarily to serve AI data centers. There will clearly be huge additional demand for electricity, but how much of that will be captured by natural gas.

Let's look at the alternatives. Certainly, renewables will play a major role, but can't handle the entire load given AI needs for uninterrupted power 24/7, not just when the sun is shining or the wind is blowing. But can't this be fixed by [indiscernible] wind or solar farms with massive batteries the store power and release it in the steady stream when needed. Well, that sounds intriguing, but there are serious drawbacks to this option because batteries are expensive and limited in the time they can cover and renewables of the size to serve AI centers require enormous space. A recent article in the New York Times of all places, estimated that to continuously produce just 1 gigawatt a solar farm would need 12.5 million solar panels and over 5,000 football fields and wind turbines would require even more space. Another source of power is nuclear, which generates steady power from relatively small footprint, but this is an industry that unfortunately has been basically dormant for over 40 years and new nuclear facilities are very expensive and would likely take 7 to 10 years to come online. This means that AI sponsor would not have the facilities when needed, and we'll be handling billions of dollars that the demand will still be there a decade or so from now.

That leaves natural gas, which is abundant and reasonably priced and the infrastructure to produce power from natural gas is relatively quick to build. Reasonably like I've just outlined is why we believe that AI data center needs will supplement in a very meaningful way the tremendous increases in LNG feed gas demand and in combination of the 2 drivers will ensure a huge and growing market for natural gas in the years and decades to come. Now let me conclude by again emphasizing the long-term strategy at Kinder Morgan. We are a prolific generator of cash and are fortunate to have the majority of our assets employed in a true growth segment of the energy business namely the transportation of natural gas. These 2 characteristics dovetail nicely. The tremendous growth in natural gas demand drives the opportunity for expanding and extending our pipeline and terminal networks and adding new facilities, as evidenced by the $9 billion plus of projects already approved by our Board, and we generate the cash internally to fund those projects while maintaining a healthy and modestly growing dividend. Now to be clear, we have to complete these projects on time and on budget, but our track record in that regard is good, and we're benefiting from a federal regulatory process that is more supportive of projects like ours.

While our base business is relatively flat, these capital projects will drive substantial growth in EBITDA and EPS for years to come. This is a simple but in my mind, very compelling strategy. And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. We're pleased to report another strong quarter with EBITDA up 6% and adjusted EPS growing 16% year-on-year. These results reflect the strength of our underlying business and the continued execution on our growth projects. We currently expect to exceed our full year budget due to the contributions from the Outrigger acquisition. This outperformance would be greater if not for lower-than-budgeted [indiscernible] prices and RNG volumes. Currently, the RNG volumes are much closer to budget, but RINs prices remain weak. The natural gas segment, which accounts for 2/3 of our business is outperforming its budget, even excluding Outrigger. Our expansion backlog remained flat at $9.3 billion, with the approximately $500 million of new projects offset by projects placed in service. The backlog multiple continues to be below 6x, consistent with our disciplined approach to capital deployment. The mix of new projects added to the backlog this quarter has split roughly 50% natural gas, primarily supporting power generation and 50% to refined products tankage.

Looking ahead, our opportunity set remains exceptionally compelling. We're actively pursuing over $10 billion in potential projects, primarily in natural gas underscoring the continued demand for our services and the strength of our platform. As I mentioned last quarter, the scale of opportunities we're evaluating today is comparable to when our backlog stood at just $3 billion highlighting the consistency and the resiliency of our growth pipeline. Our gas infrastructure more than 66,000 miles of pipeline connecting all major basins and demand centers. positions us as a critical player in energy infrastructure.

Today, we transport over 40% of the natural gas in the United States, including more than 40% of the volume headed to LNG export facilities the gas fueling U.S. natural gas power plants and 50% of the gas exported to Mexico. Looking forward, our internal projections estimate 28 Bcf a day increase in natural gas demand by 2030 driven primarily by growth in LNG exports as well as power and exports to Mexico. Wood Mackenzie forecast a similar trend, projecting 22 Bcf a day of growth in overall natural gas demand. With our strategically located assets, we are well positioned to capture a meaningful share of this expansion. Our current $9.3 billion backlog is a strong foundation for long-term high-quality growth. A very significant portion of this backlog is supported by take-or-pay contracts, providing both stability and visibility into future cash flows. And as we continue to advance our development pipeline, we expect to convert a portion of the $10 billion opportunity set into additional backlog, further reinforcing our growth trajectory. We remain confident in our strategy, our execution and our ability to deliver long-term value for our shareholders.

And with that, I'll turn it over to Tom Martin to walk through the business performance in more detail.

Thanks, Kim. Starting with the natural gas business unit. Transport volumes were up 6% in the quarter versus the third quarter of 2024, primarily due to LNG deliveries on Tennessee Gas Pipeline new contracts from expansion projects placed into service on the Texas Intrastate system and increased Permian deliveries to Waha and Mexico on our El Paso natural gas system. Natural gas gathering volumes were up 9% in the quarter from the third quarter of 2024, with growth across all our G&P assets, the largest impacts from our Haynesville and Eagle Ford systems.

Sequentially, total gas gathering volumes were up 11%. We experienced a significant ramp from our producer customers during the quarter to meet the growing LNG demand. The gathering volume growth trend continues in the early days of the fourth quarter, most notably on our Haynesville system as it is approaching new daily volume records in October. For the full year, we now expect the gathering volumes to average 5% above 2024. And looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation and storage capabilities in support of the growing natural gas market.

For example, we are exploring more than 10 Bcf a day of natural gas opportunities to serve the power generation sector. In our Products Pipeline segment, Refined product volumes were down 1% in the quarter compared to the third quarter of 2024. For the full year 2025 refined products volumes are forecasted to be about 1% higher than 2024 and in line with our budget. Crude and condensate volumes were down 3% in the quarter compared to the third quarter of 2024. More than all of that decline is driven by taking double age out of service earlier this quarter for the NGL conversion project. On Monday, Kinder Morgan and Phillips 66 launched a binding open season for transportation service on the Western Gateway Pipeline, a newly proposed refined products pipeline system that will facilitate the movement of products from origin points in Texas to key downstream markets in Arizona and California with connectivity to Las Vegas, Nevada. This open season is scheduled to run through December '19.

Following the successful open season, the Western Gateway pipeline and KMI's SFPP East line will be jointly owned by KMI and Phillips 66. We believe this project provides an attractive refined products alternative for markets in Arizona and California, given the decline in California refining market. In our Terminals business segment, our liquids lease capacity remains high at 95%. Market conditions continue to remain supportive of strong rates and high utilization at our key hubs in the Houston Ship Channel and New York Harbor. Our Jones Act tanker fleet is fully leased today through the remainder of 2025, assuming likely options are exercised, the fleet is 100% leased through 2026 and 97% leased through 2027. We have optimistically chartered a significant percentage of the fleet at higher market rates and extended the average length of firm contract commitments to nearly 4 years. The CO2 segment experienced 4% lower oil production volumes, 4% higher NGL volumes and 14% lower CO2 volumes in the quarter versus the third quarter of 2024. For the full year 2025 or volumes are forecasted to be 4% below 2024 and 1% below our budget. With that, I'll turn it over to David Michels.

Thank you, Tom. This quarter, we're declaring a quarterly dividend of $0.295 per share or $1.17 per share annualized, which represents a 2% increase over our 2024 dividend. For the third quarter, we generated net income attributable to KMI of $628 million and EPS of $0.28 per share both in line with the third quarter of 2024. Last year's results included favorable mark-to-market impacts on hedges and a onetime noncash tax benefit, both of which we treated certain items. Excluding those items, adjusted net income and adjusted EPS grew 16% year-over-year, delivering strong double-digit growth. This growth was driven by greater contributions from our natural gas expansion projects placed in service, the Outrigger acquisition and strong demand across our natural gas footprint for natural gas capacity and related services. Moving on to the balance sheet. As we've continued to take a disciplined approach to capital allocation, our balance sheet has strengthened. Our net debt to adjusted EBITDA ratio has improved to 3.9x at the end of the third quarter down from 4.1x at the end of the first quarter, which was immediately following the Outrigger acquisition. Year-to-date, our net debt has increased by $544 million, and here's a high-level reconciliation. We generated cash flow from operations of $4.225 billion. We've paid out dividends of $1.95 billion. We paid or spent $2.245 billion of total capital. the outride acquisition was $650 million, and all other items were a source of cash of approximately $75 million, which gets you close to that $544 million increase for the year. The rating agencies have recognized our strength in financial profile. And in August, Fitch upgraded our senior unsecured rating to BBB+. We were already on positive outlook by both S&P and Moody's and we look for a favorable resolution of those in the near term. As Kim mentioned, we expect to exceed our 2025 budget.

And as a reminder, we budgeted to grow adjusted EBITDA by 4% and adjusted EPS by 10% from 2024. So with the outperformance we expect to deliver even larger year-over-year growth. As we mentioned last quarter, the budget reconciliation bill delivers meaningful tax benefits for us, primarily from full expensing of investments. In addition, recent adjustments to the corporate alternative minimum tax are expected to provide additional substantial tax savings beginning in 2026. So we are poised for a very strong full year 2025. We're on track to beat our budgeted our budget and delivered double-digit earnings growth. We sanctioned additional high project high-return projects that will support future growth. We've improved our balance sheet resulting in enhanced credit ratings, and we expect meaningful cash flow benefits from tax reform, which will generate additional investment capacity. And with that, I'll turn it back to Kim for Q&A.

Michel, we'll come back on, and we'll take questions.

[Operator Instructions] Our first caller is [indiscernible] with Barclays.

Afternoon. I wanted to go back to your growth outlook and specifically the over $10 billion opportunity set in unsanctioned projects under development up, I think, from the previous $7 billion to $11 billion range. What has driven the seemingly improved outlook over the past few months -- how quickly do you think you can commercialize these growth opportunities? And where are you seeing the most interest for expansion projects amongst your customers.

So on the $10 billion, that's all the opportunities that the opportunities that we're pursuing right now. It's mostly natural gas. It supports the themes that we've mentioned here today, so export LNG, power, but there's also projects that exports to Mexico and industrial growth. And as I said, the opportunity set is very similar to when our backlog was at $3 billion. So we haven't seen any diminishment in the projects that we're looking at. These projects are mostly across the Southern U.S. So they go all the way from Arizona to potentially Florida. And most of them are in smaller in size, I'd say, less than $250 million, but there are a few that are $1 billion plus. So it's all of the board. It's power in Arizona, power in Texas power in New Mexico Power in Florida. -- if we need more egress from the -- from all the producing basins, the Haynesville, potentially the Marcellus Utica we need more gas moving to LNG. As Rich said, we've 9 Bcf of gas demand from the projects that have FID recently. So I mean it's across the board. And then today, we have potential project we're working on with respect to Western Gateway. So there's a lot of different opportunities out there.

And on that last point, Kim, following this week's announcement of your open season for Western Gateway, can you talk about your projects positioning relative to [indiscernible] competing Sunbelt project? And assuming that Western Gateway solicits sufficient commercial interest during the open season, can you talk about potential gating factors, regulatory or other rides that Kinder and [indiscernible] is many to address before the project can be sanctioned?

So relative to the competition, I think their pipeline just goes into the Phoenix market. Currently, the Phoenix market is by us from the left as well as from the East. The project -- the proposed project with P66 and us would reverse our West line build a new pipeline from Borger to Phoenix. And so we would be sending barrels from the East into the Phoenix market. and reverse our West line so that you could potentially barrels could move on into the California market and potentially into the Las Vegas market. So I think it's -- from our perspective, it's a very good project for Arizona. Arizona is a growing market. So it gives additional capacity to serve the Arizona market. Arizona is no longer dependent on California, where California has got some closing refineries. California gets potentially additional barrels coming to the California market. To the extent there are additional closures in California. And I think it's a great project because you're accessing multiple markets, you're not just going to 1 market. So in terms of the open season ends on December 19. And then from there, we'll need various regulatory approvals and we would target a 2029 in service date.

The next caller is Jeremy Tonet with JPMorgan.

Good afternoon. Just want to follow up on some of the comments you had said there with KMI seeing an opportunity step more robust at any time in the company's future. And just want to, I guess, see if we could expand upon that in any way? And just wondering how you think about the landscape given Kinder's competitive positioning, it seems like it's a competitive market out there. And any thoughts that you could provide around that? And I guess, what could be the cadence of how this capital could fall into plan at a high level over time?

So a couple of things. I think I walked through some of the background on the $10 billion in opportunities. But with respect to -- on competition, look, we're not going to win all these projects, but we're going to get our fair share. And what makes us very competitive is our existing footprint, which provides us with opportunities to build off of that footprint and we can provide our customer services that other competitors can't offer. And so -- including storage, and so that's really, at the end of the day, what differentiates us from our peers. We also have a good track record on bringing projects in on time and on budget, which I think is helpful when time is important to our customers. And that's especially true, I think, for some of the data center and power customers. So I think in terms of how this comes -- how this -- the products of bringing these to that is -- that's hard to project. And so I can't tell you exactly what that's going to look like, but I think will bring significant projects to FID in 2026 based on that $10 billion backlog.

Got it. That's very helpful. And then just a smaller question for me as it relates to the guide. It just seems like the language changed a little bit with how much going to exceed the guidance by out regular in the 2Q versus 3Q? And it seems like it's a little bit less at this point. Just wondering what other, I guess, changes in the backdrop you see versus the 2Q.

Yes. I mean there was a slight change on that, and it's really related to the [indiscernible] the RNG volumes and the REMS price weakness.

Our next caller is [indiscernible] with Jefferies.

Maybe just picking up where the other guys just left off here. Can you elaborate a little bit on how you're seeing the opportunities emerge as it pertains to the shadow backlog? I know you gave some of these examples smaller and larger, but maybe regionally and how they pertain. I mean, obviously, we've seen examples recently in the last week here with a private backed pipeline FID in the Gulf Coast. Could you elaborate a little bit on the power opportunities, both in as it pertains to Texas, and also maybe as it pertains to the backlog opportunity in the Southwest, I mean, obviously, we saw what your peer announced in the last few months, but how do you think about the future on the gas side in the El Paso system.

Yes. I mean I think there's continued power development. A lot of it is for data centers, but there's other things that are driving power development coal retirements that some of those have pushed out some, but some of them are still -- some of them are still happening. And so what we see and there you need more peakers to back up renewables, which is what we're seeing in Texas. And so on the data centers and the power conversions, I mean, we're seeing that in Mexico, we're seeing it potentially in Arizona, some places where maybe the pipeline that got it now recently doesn't go, wouldn't serve. We're seeing some in Colorado. We're seeing some potentially more in Arkansas in Florida, Again, I'll just repeat some of these and the CPL come in. We're seeing opportunities to build out of the Haynesville to get gas further to the market. get more volumes potentially coming out of the [indiscernible] Utica. So there's a lot of different opportunities. Storage is a huge factor right now. people need a lot of storage. And so we're looking at some opportunities to expand our storage and some new greenfield opportunities.

So one thing I'll add, especially out West, is we have strong connectivity to Mexico. So when you think about the power demands there, those are also rising. -- and not only from the base organic power, but Mexico also is evaluating their own data centers. And so our footprint, especially out West is very well connected along those lines. And then when you look out in the Southeast, you've seen the IRPs that have been put out by all the various states. Clearly, there's demand that's coming. And as you all know, we're well positioned in that market to try and capture some of that growth. when I go to the Gulf Coast, we continue to debottleneck and the plumbing to be able to get the molecules from the supply zones to the consuming markets. I think that's something you can kind of takeaway on things that we're working on. And then all of this gets put together with our -- when we evaluate storage and how to integrate storage and then supply access to these consuming markets. Those are kind of the big themes that we're seeing on the horizon.

Got it. And if I can pick a little bit -- I know you just alluded to the Southeast opportunities on does that line up with what we're seeing right now in the generation resource planning? I mean, obviously, we've upticked it pretty meaningfully here of late. Is that presently reflected? Or is there a little bit of a mark-to-market to happen on your side? And then also on the Western Gateway, if you could just clarify what the ultimate economics are on your side or at least the total dollars [indiscernible]

So I'll take the first question, and I'll turn it over to to Kim and Mike on the second one. So Southeast, look, in terms of what we're in that $10 billion that Kim was referring to, that is taking into account some of the IRPs that are out there, especially in the Southeast. I mean that's what we see as infrastructure that's needed. And so I think to answer the first question, that is a subset of that $10 billion. And then I'll turn it over to Kim and Mike for the second piece.

I mean, in terms of the cost to build that pipeline, we're not going to get into that because as you know, there's a competitive project out there. And so the -- we don't want to compromise that position at this point in time.

Our next caller is Michael Blum with Wells Fargo.

Wanted to ask about Highland Express, the NGL conversion project. Just in terms of where do you stand on committed initial volumes? And where do you think that can go? And then I noticed in the press release, you talked about potentially some takeaway out of the Powder River as well. So I wonder if you can expand on that.

Yes. So sticking to our previous discussions, it's on track. We're on track to be ready first quarter next year for our initial commitment. Obviously, you all know we're also at a very aggressive competition with the incumbent there, so I won't get too much into the details on what's next. That being said, we have some assets that we're effectively repurposing to be able to position ourselves to draw incremental barrels to the pipeline. And I will leave it at that until we actually have the next set of announcements to make, hopefully, very soon.

Okay. Fair enough. And then I wanted to ask you about the behind-the-meter opportunities. I know in the past, you've talked about maybe coming up with a solution with partners. So just want to see where that stands and if that can be a meaningful driver? And if that's part of that [indiscernible]

I think the answer is still -- that's not something that we're interested in doing. I think we've got plenty of opportunity, plenty to say grace over in our existing infrastructure business. That is what we are good at, of what we know how to do. And therefore, the growth that we're projecting is very high-quality growth, as I said, largely backed by take-or-pay contracts. I think maybe we're missing a little bit is I think in the past, what we said is if there was a data center or something that wanted us to invest for some reason, maybe we might make a very small investment there. But that would just only be to facilitate a project getting done. That is not where we want to invest our dollars. And so what I would say is it is unlikely that we invest behind the meter.

But what -- but to add on to what Tim just said, we are looking at working with our partners to supply gas in certain instances to be able to support a consortium of folks to be able to provide reliable power. I mean I think that's the way you would look at our participation in the opportunity. we would be looking to build the infrastructure to be able to support that.

We'll supply the gas.

Our next caller is John Mackay with Goldman Sachs.

I'm going to go to the shadow backlog, too, I guess, not to keep running through the same thing. But I guess I just want to ask one more way. When you're looking at the $10 billion, how much of this is look at the competitive environment, we'll see what we win, we have a lot to bring to the table versus really waiting for actually that demand to materialize the next LNG FID, some larger power built out across the Southeast, et cetera. Maybe just what are the kind of buckets between the 2 in terms of what you see in front of you?

I mean, these are projects where we are actively talking to customers about them. And so I think we're having conversations with people we are putting together estimates on what things would cost. We're looking at returns. These are all things that are active conversations internally.

That's fair. Maybe just follow-up second question. I appreciate the comments on the guide around the RNG side being softer. Can you talk about the rest of the business? I mean, gas was relatively strong. Any more kind of one-offs in there? Or is this a kind of healthier run rate?

I think gas is very strong. We didn't have much of a winter or much of a summer. And they're still -- even if you take out the Outrigger acquisition, they're still going to nicely beat their budget. Terminals is also doing very well this year and should exceed its budget products, I'd say, it's kind of right on its budget, slightly short, but it's pretty small. And then where the weakness is really in RNG and a little bit on CO2.

Our next caller is [indiscernible] with Citi.

I wanted to start with the 2026 outlook. I know we're going to be getting a formal update from you guys in a few weeks. But maybe just at a high level, if you just talk about some of the variables you could see impacting the various segments? And maybe any reason 2026 growth wouldn't at least sort of match up the 2025 growth rate?

Well, I think we're going through a process right now. And so I think it's too early to talk about what the growth rates might be. But in terms of if you want to go tailwinds, headwinds, something like that, tailwinds, we've got expansion projects. We've got a full year of the '25 that we'll get in '26. And then you've got partial year '26 growth projects. We've got contract escalators in our terminals business and our products business, interest rates are coming down. So that should be a tailwind for us not expecting a significant increase in taxes, given what we've seen on the big beautiful bill and the bonus depreciation. As always, we see a little bit of decline potentially in CO2 in oil volumes. And then what's unknown is I think commodity prices at this point in time will just have to see where those come out.

Yes. Fair enough. Second one, if you could believe it. I do have another follow-up on the opportunity set. And so just curious, how we should think about the time frame that either the $10 billion or the 10 Bcf a day captures I'm asking from 2 different perspective. To the extent these are all opportunities you're sort of chasing within the decade, is there an opportunity here to see investment per year CapEx go up above $3 billion. And then conversely, how should we think about your ability to maybe deliver more short-cycle cash flows. A lot of these projects have later dated great projects. But just curious if you could sort of fill the front end up more, too.

Yes. So I think if you think about -- these are going to be both on regulated projects and regulated projects. And so the regulated projects now have a shorter time cycle than they have in the past. And so that's very good. I think the FERC has gotten rid of a 71. So that 5 months has gone -- that 5-month waiting period is gone. And I think they're working really hard to get permits delivered more quickly. So that's going to shorten that should shorten up your capital cycle some. I think the gating item is probably going to be compression. And so that's going to -- that will limit how much you can probably shorten it up. But I think in general, the FERC projects are going to be 3 -- a little over 3 years probably from the time you sanctional to the time you're in service. And I think shorter capital will be on the gathering side and then on all the Texas intrastate projects, all the pipelines in Texas and then potentially other intrastate pipelines in other states. So generally, I think you're going to start filling up the out years but you may have some near-term capital, which increases '27, '28 CapEx somewhat. But I think we have plenty of free cash flow and balance sheet capacity to be able to handle any increases that we see above $2.5 billion or $3 billion if you think about it. I'm not giving any guidance here. I'm just going out a rough number. If we have $5.5 billion of DCF, and you've got $2.6 billion of dividends, you've got $2.9 billion of cash flow to support the expansion projects. Then our balance sheet right now is sitting at 3.9x every 0.1x as $800 million. I don't -- we're probably not going to run it up to 4.5%, but you've got a $3 billion-ish at least a room there. And then over time, that debt to EBITDA is going to come down more as we bring these projects online. And so that balance sheet capacity is going to increase over time. And then I think there is also very attractive third-party capital out there if we wanted to access it. So I think we've got I'm not worried about capacity to finance these expansions. I think they are good return projects and we will find ways to do them without compromising our balance sheet.

Our next caller is Keith Stanley with Wolfe Research.

Just wanted to follow up on Western Gateway and I know you don't want to say a total capital cost. But my questions are more on the structure. So if Philips is building the new pipe and I think your capital investment is just a line reversal and maybe some tankage. Is it fair to think your portion of the CapEx is a lot smaller in this project? And then the second question is the structure of the JV, so you're contributing SFPP, they build Western Gateway. And then is it roughly like a 50-50 JV from there?

Yes. I think it's going to be around a 50-50 JV. And so yes, because we're contributing assets, our capital expenditure for the new assets would be a little bit less than what [indiscernible] would have to contribute.

Okay. Great. And then second question, I think, Kim, you referred to potential TGP projects that would egress out of the Appalachia region. I think there's been a few capacity reservations for projects. Can you just talk about what you think is possible or doable to increase capacity out of Appalachia on [indiscernible]

Yes. So this is Steve, Keith. Yes, we've been working diligently on trying to find ways to get incremental egress out of the basin as these consuming markets develop with the demand that Rich Kim talked about earlier, it's incumbent on us to get incremental gas out of the basin. We're in terms of what that capacity amount is still being worked on. But needless to say, I would say just rough numbers, north of half of Bcf is what we're trying to get but still early, and I take that with the grant auto we're done with all the diligence.

Our next caller is [indiscernible] with TPH.

Maybe going over to the Haynesville, it sounds like volumes continue to grow there. I think on the last few calls, you guys have mentioned you're getting close to capacity. Maybe an update there? And then is this from your largest customer on that system? Or are you seeing private start to flow volumes as well?

Yes. So one, we are -- as Tom mentioned earlier, we are pretty much at capacity. We're just waiting for when we cross the record, hopefully, any day now. But I think it's not only our largest customer, but there are a few of the other privates that are also looking to increase their drilling in response to the demand that's coming our way. And so we do see meaningful ramp up next year in the Haynesville.

Yes. And I think quarter-over-quarter, in the Haynesville volumes are up 15%. So we're seeing our customers bring on these volumes and you might remember, we announced last quarter a $500 million investment in the Haynesville, which is -- it's a lot of treating capacity, but also some incremental pipe capacity to be able to accommodate our customer volumes.

Got it. That makes sense. And then maybe moving over [indiscernible]

We expect it to be one of the strongest -- probably the fastest-growing basin. Our internal projections are it's going to grow almost 11 Bcf a day between 2024 and 2030. So it's going to go up to probably 23 Bcf a day in terms of production. So I think we're seeing opportunities today, but I expect we'll continue to see opportunities over time both to invest in the Haynesville and to take molecules away from the Haynesville.

Got you. No, that all makes sense. I appreciate the color. And then maybe 1 on the Permian West expansion open season it looks like that gas is heading west bound. Just curious if that could be upsized if the demand is there. And then maybe some color on the customer mix. There's obviously some data centers where that expansion is heading. Is there demand also beyond Texas as well?

Yes. Look, I mean, I think -- I believe you're referring to the the smaller open season that we've got out there going west, that is to serve power. And obviously, as the open season closes, we'll evaluate the bids and look at what we can do to accommodate the capacity. Clearly, in and around that area. And then if you go to flip over 1 state over into New Mexico, there's a lot of activity on the power side. And so we're just going to have to evaluate how the bids come across.

Our next caller is Brandon Bingham with Scotiabank.

Just one quick one here for me. I would just be curious as to what you guys think the longer-term market dynamics are in California for the refining products market and whether or not there's upside potential for Western Gateway or any other future growth into that market? Just any high-level thoughts you have?

Yes, I'd say we wouldn't want to speculate on the California markets, what's happening there. But if you think about our reversal of the West line and that volume need now to be filled through the new gateway line into Phoenix, you've got this access into California. So depending on what that California refining market does. You've got the capacity across that West line to continue to grow with changes in that market. And then as we've talked before, you also have access beyond through [indiscernible] into Las Vegas, Nevada.

Our next caller is Jason Gabelman with TD Cowen.

I wanted to ask about the shadow backlog as well. And you mentioned both kind of large-scale and smaller projects. And I was hoping to get a bit more color on the larger projects. If I look at the backlog that you have right now in projects and execution, it's kind of large projects that are all serving Texas and Southeast. Should we assume the large projects in the backlog are kind of similar markets they serve or is it kind of a bit different? I noted, for example, you mentioned Mexico a couple of times and wondering if that's one of the larger projects in the backlog.

Well, so all these projects are competitive, almost everyone that we're working on. And so that's why we haven't given it -- we've tried to be very broad in how we describe but this drives the backlog. So what I would say about the larger projects in the backlog is generally, they are around the themes of supporting export LNG and supporting power.

Okay. Understood. And then my other question is just on M&A. Given there's starting to see once again a bit of a larger multiple dispersion between natural gas and liquids names? And given you do have a decent sized nonnatural gas business. I wonder if there's opportunities out there or hold in the portfolio that you'd be interested in filling especially if crude oil prices fall and some other companies become available?

Are you talking about buying?

Yes.

So look, I mean I think acquisitions, M&A is always opportunistic. And so we will look at opportunities for assets that set our strategy, which is owning energy assets, energy infrastructure assets. Fee-based and we can do it on returns that we think are appropriate on a risk-return basis and that we can do within keeping our balance sheet within the metrics to 4.5x debt to EBITDA. So I don't -- again, I think our view is there's unlimited capital for good returns, good risk return opportunities. And so we'll continue to look at those. We've done some in the recent past. We haven't done anything that is huge, but we did 1 at the end -- the beginning of this year in Outrigger. We did 1 last year as well. And so those things are hard to predict. But I think we either have the capital depending on the size or can find the capital to pursue those when they come about.

Our next caller is Dave Winans with Prudential.

You guys got a great opportunity set in natural gas, but just kind of switching gears a little bit here to the CO2 business at least one operator is talking about potentially using CO2 suites in some of these type plays out in the Midland and Delaware basins and such. Is that something you guys have looked at? Does that represent a business opportunity for Kinder Morgan? Or do you need to see more proof of concept around something like that?

Are you talking about participating in that Dave? Or are you talking about supply [indiscernible]

Either.

And I think with regards to supplying the CO2, we certainly would be interested in that. I think in terms of the other side of that, I think we would have to look at that a lot more closely and really seriously look at the risk/return opportunity there before we would consider investing.

And it depends on my understanding on a lot of these, Anthony, is it depends on how they frac that deal to begin with. So whether they would be successful CO2 candidates. I think any time you're doing something new, you need to get a much higher return on that to compensate for the risk of doing something that you haven't spent a lot of time doing before. Obviously, we know what we're doing in CO2, but we haven't done a lot of flooding from these previously for fracked fields.

Our next caller is Jean Ann Salisbury with Bank of America.

I just wanted to follow up on the comments that you've made about needing to build pipelines from kind of Tier 2 basins, not the Haynesville to the LNG that's coming online. One issue, I guess, that I had been thinking about is that it's a little bit unclear who would be willing to underwrite these contracts with the LNG builders kind of being linked to Henry Hub and the EMPs maybe not wanting to take long-term contracts. So I was just wondering if you could give any color on if you see that being kind of a constraint to these [indiscernible] and just if you think it will be a mix of end users, E&Ps and marketers on those trends of pipelines?

Yes. I mean second-tier basins, something like the Eagle Ford, I think, is very well positioned. And I think there's, one, that would be great for us because we've got a great position in the Eagle Ford -- and I think that is a basin that could grow more than what is in a lot of the current projections. In a place where infrastructure is relatively easy to build. And then I think the Haynesville has a lot of growth to come to support this. But [indiscernible]? .

Yes. When we look at this, I think as the markets start figuring out what -- where they can actually get a molecule that will drive. So I would -- the way I would answer the question right now is that would be driven primarily by the market pulling from the supply and then some of the producing base producers kind of complementing, it's going to take a little bit of both, especially in the second-tier basins. And I think that's going to evolve over time as the plumbing gets kind of discovered where we can get gas where you can source gas and how that moves through the networks to the grid -- the pipeline grids to be able to get to the consumer. That's the way I would think about that.

At this time, I am showing no further questions.

Okay, Michelle, thank you very much, and everybody, have a good evening.

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.

Hi, everybody. For those who don't know me, I'm Keith Stanley. I cover Midstream here at Wolfe Research. Very happy to have David Michels, CFO, of Kinder Morgan, come join us.

We're going to go right to Q&A. Feel free to throw up -- throw in any questions, just raise your hand. I'm more than happy to throw you into the mix here.

Maybe we could start, David, a lot of excitement around to gas infrastructure and a couple of different ways to play it. What would you say differentiates Kinder Morgan as it relates to positioning for LNG demand, for power demand and execution risks as well?

Okay. Well, first, thanks for having us, Keith. We've had a great set of meetings so far. So looking forward to the rest of the conversations we're having.

I think the single most important factor in terms of securing additional infrastructure opportunities, a great landscape out there, great demand growth for natural gas, particularly in the U.S. But the single most important factor in terms of who is going to secure opportunities is existing network, existing assets.

And we're fortunately positioned where we have more interstate natural gas miles of pipe in the U.S. than any other competitor. And most of the competitors out there, we have more than double their network -- interstate network miles of pipe. And so we're very well positioned. And I think that's played out over time.

We've got -- we touch 40% of all of the molecules, U.S. natural gas molecules that are produced on a daily basis. We supply 45% of all the molecules that are used as feed gas for liquefied natural gas exports today. We supply about 40% of all of the natural gas going to power generation facilities in the Southern states, which is where we're seeing most of the power generation growth, and we supply about 50% of the molecules going across the border to Mexico. So we've got a really, really nice footprint.

And I think that is because that's the most critical factor in determining who's going to be well positioned to obtain additional opportunities, I think that positions us very well. And then there were a couple of additional questions you throw...

Just on risks. How you -- execution risks for projects.

Yes. So I think we're going to get our fair share beyond the $9 billion of projects that we've already secured. I think there are going to be more that we will be sanctioning significantly more that we'll be sanctioning.

So the risks are permitting risks, construction risks and the competition, of course, but we talked a little bit about that. So permitting, it's been a very favorable environment for federal permitting and some of the other entities that weigh in on permitting generally. So we've seen some streamlining. We've seen some efficiency. The FERC permitting process has been streamlined by 5-plus months. It used to be for a multistate pipeline build.

The 7(c) certificate process used to take 24 months, and we've already seen that get accelerated by 5 months and potentially some more. So that's really helpful.

The construction and the execution of the actual build is now where we're focused. And so far, so good. We're seeing good availability of contractor labor, skilled contractor labor, which is very important. We've just gone through the construction bids for our 3 largest projects, and we had very good participation in the bidding process.

The rates came in at or even favorable to the budgeted cost that we had expected. And so, so far, that portion of the business remains quite robust, and so it's not a limiting factor. The equipment is starting to get a little bit tight. Turbines, compressor units is getting a little bit tight. So we're keeping an eye on that. We're trying to stay ahead of that. And we've done a good job on the existing projects that we have, but we'll need to continue to consider that for future projects.

The areas of the country where you're building, that's also a very big factor in terms of the ability to secure the right of way to construct through those areas of the country. There are more favorable areas than others. The coasts tend to be a little bit more tricky, particularly the West Coast. Texas, Louisiana, the Southeast states tend to be a little bit more open in terms of pipeline builds.

You mentioned seeing a lot more opportunity still. So the sanctioned project backlog has gone from, I think, $3 billion, maybe 18 months ago to $9 billion today. Do you expect that to keep rising over the next year or 2? And where are you seeing the most opportunities to grow that?

Yes. So our objective is not to grow the backlog, but to obtain as many sanctioned projects as we can that meet our return threshold. So that means we're going to see some potential volatility in the backlog as we're building the projects that are in that backlog.

Once they're built, we bring them out of the backlog, and then we don't put new ones in until we sanction them. But we have identified more than $10 billion of real specific projects that we are currently developing beyond the $9 billion that we have in the backlog. So we have good visibility into ways that we can replenish and potentially even grow the backlog, but there'll be quarters where it will be up and down a little bit.

But I think what we're working on right now is a set of opportunities that will give us confidence that we'll be able to extend the growth that we're currently anticipating with that $9 billion of backlog. We'll be able to extend that growth period for years into the future.

And when you say over $10 billion of opportunities on what time line would that be likely that you can move forward on that bucket of projects?

Some are earlier than others. The smaller ones are -- tend to get sanctioned a lot more quickly, the sub-$250 million, but there are a couple of bigger ones in that $10 billion number, $1 billion plus -- those will take a little bit longer.

And they're also in different stages of maturity, too. And some of them are a little bit further ahead where we could see Q1, Q2 of next year. I think we have some good opportunities that might be ripe to come to the market at that point. You mentioned -- you asked about geography and where we're seeing some of these. It's really remarkable that we're seeing these opportunities all over.

It's not concentrated just in Texas or Louisiana, although we are seeing plenty of opportunities in Texas, Texas being supported by all of the massive LNG build-out on the Gulf Coast, continue to see development of industrial demand, exports to Mexico continue to increase. So all of that is adding to -- and power generation. Now power generation all over the state is adding to the overall demand for natural gas, and that's creating great opportunities for us to debottleneck our system.

We've got a massive Texas Intrastate system that runs up and down the Gulf Coast. And so debottlenecking opportunities, connection opportunities along the corridors. Additional gas keeps coming in from the Permian, and that needs to get to a market. So one of our big projects was to take some of that gas over into the Port Arthur area with our Trident project, which has been sanctioned and is under construction. But just great atmosphere to build new projects there and tremendous number of opportunities.

Louisiana is an excellent opportunity set, too, because of all of the gas that's coming out of the Haynesville, which is starting to ramp up now, several corridors of pipelines that are being built down into the LNG corridor. And we're working on our own gathering and processing and treating build-out of our Haynesville gathering asset.

In the Southeast, we've already established 3 large projects going east, and we're seeing additional opportunities for gas growth on that corridor. So this is the example of where one project leads to another. We're building out South System 4 Mississippi Crossing, our EEC expansion and then our Bridge project all the way into South Carolina. And we're already seeing on the backbone of those committed projects additional opportunities coming to our footprint, which is great.

Westbound, we missed out on the Copper State project, but there are other projects that we're going after in Arizona and elsewhere to try to accommodate some additional natural gas demand going westbound. And then our NGPL footprint, which stretches from Texas up into Chicago. That one has the opportunity to accommodate data center demand growth and power generation growth up and down its footprint. And we're seeing it not only in its Texas and Louisiana footprint, but Arkansas all the way up to Wisconsin. So we're seeing these opportunities throughout the country, which is pretty fun.

Go ahead, John.

Maybe can you just provide some context to the $10 billion of development and the $9 billion backlog versus a year or 2 years ago like [indiscernible] just to give us a sense of sizing what you're seeing there versus [indiscernible].

Yes. I would say 3 to 5 years ago, I think our actual backlog was $2 billion or $3 billion. It was small. And the opportunity sets that we were working on were $1 billion or $2 billion worth, primarily numerous smaller projects that you could add up.

The beginning of 2024 is when we started really seeing some specific opportunities develop that would help accommodate the very large natural gas demand growth that we're seeing. The natural gas demand growth has been there for that whole 5-year period. But I think the market wasn't ripe yet to start sanctioning the projects to accommodate that growth.

And these LNG facilities have been on the drawing board for years as they go through their permitting process, their construction process, their financing processes. And so we saw that visible growth coming to the market, but the infrastructure to accommodate that growth wasn't being sanctioned yet.

And then about 2 years ago is when we started seeing a lot of that start really come to market. We sanctioned $6 billion of projects in the last 18 months. And then the opportunity set, the $10 billion of projects that we're working on right now, I think we probably would have said the opportunity set was a similar size 12 months ago.

The difference is now that opportunity set has really developed into -- potential into more like [ PUD, ] right, more like more developed specific projects where we're working with a counterparty and we're trying to get contracted terms.

Do you see [indiscernible]?

It could. I think we're pretty happy with the $10 billion. And I think we're going to be able to -- what we're working on right now is trying to secure as many of those as we can. But the next set of projects beyond that, we're starting to have some early conversations on those as well.

Any others? So with that backdrop on growth and just the inflection of investment opportunities, maybe you could walk through the investment proposition for Kinder as you see it as far as growth in the business over the medium to long term, what your expectations are for the base business and how all this investment translates to growth in your EBITDA and your dividend?

Yes. So we've said that it's going to be a little bit lumpy as projects come on and new projects get sanctioned and so forth. But we think we'll spend approximately $2.5 billion a year, and that is sufficient to grow our EBITDA and I should say, our base business has stabilized.

We went through a period of time where we had some ups and downs, but it's stable -- stabilized and quite visible growth into the cash flow in our base business. And so we think that those new development projects that we're building will contribute EBITDA that will drop to the bottom line. And we think that, that $2.5 billion will grow our EBITDA in the single-digit annual growth rate area, which then drops to an EPS in the high single-digit EPS growth area. And it will be lumpy.

There'll be some years that's higher than others. Some of these big projects come on and hit. Those are nice because the moment you turn the valve on, it's 100% of that -- Mississippi Crossing, for example, 100% of that is going to come on at one time. Some of those are phased, but -- and that will add to EBITDA leverage capacity will increase. And so we're going to be able to afford even more of these projects with internally generated cash flow. And so it's all good. And we actually see our leverage continuing to decline as these projects come on.

If you execute on the $10 billion, though, of potential projects, you have $9 billion already sanctioned. What's the probability that CapEx is going higher than $2.5 billion a year? I would think because that's almost $20 billion of investments that you have some visibility on. I would think the CapEx might start to move up from there.

Yes. I think that's a fair possibility that some of the new projects that we're going to be sanctioning will overlap with some of the projects that we have in the backlog right now that won't be in service by the time we start constructing on some of the new projects.

And so I think there'll be a period of time where there's an opportunity for us to see even more growth and more spend on our capital projects. I think we're okay with that. The -- I mean we're great with those projects because they meet the return thresholds that we've set that are well in excess of our cost of capital and are very attractive returning projects. So they're delivering a great deal of value to our shareholders.

But what I meant by we're okay with that is we're okay with spending more dollars on these types of projects. We can fund $2.5 billion out of organic cash flow, and that's going to be growing as these projects come on. We've got some spare capacity on our balance sheet today. We're at 3.9x leverage debt to EBITDA and our long-term leverage target is between 3.5x and 4.5x. And so we're a little bit on the favorable side of that, and we expect that to continue to come down with greater -- with good EBITDA growth. So we'll have some balance sheet capacity. before we would need to consider some type of an external funding source if needed.

Maybe we could shift to LNG. So we've had 5 new projects now FID just this year on top of 10 Bcf a day under construction. It looks like there's a few more that might go to. Has this surprised you as a trend, just how many projects are moving forward? Do you think we're going towards an overbuild of LNG export capacity? And what's your positioning for some of these new projects that have recently been sanctioned?

Yes. We have a macro research team -- macroeconomic research team that has a model and they put together their view on likelihood of some of these LNG facilities and have for years. And so it wasn't a real surprise to see the incremental LNG facilities get sanctioned and start getting under construction. Will there be an overbuild, is a difficult question to answer.

It depends on geopolitical international and global LNG demand versus the LNG capacity globally. What our research team suggests is the demand globally is expected to be there, but there will be some capacity that will need to go underutilized for some period of time for the next 3 to 4 years, I think. But what they're saying is they think that the U.S. molecules are favorable relative to several other geographies.

The Henry Hub continues to be a pretty cheap source of gas. The amount of additional reservoir that's available at just north of $4 appears to be quite substantial. And so while right now, in the $2.50 range, gas, it's very attractive even at $4, you're able to cover your variable costs and some of your total costs on the LNG side in the U.S.

The availability of infrastructure, storage, the reliability of the supply is all going to play a big part in the utilization, we think, of the U.S. facilities relative to global facilities. And so our team thinks that the U.S. facilities will continue to be pretty fully utilized and what gets backed out are some of the international LNG capacity.

But what we try to do at Kinder Morgan to protect ourselves from that because we can't control that. We can't control how much utilization occurs at the U.S. facilities is to sign up take-or-pay long-term contracts with our counterparties. And to the extent that those counterparties aren't investment-grade counterparties, we'll also secure substantial collateral from them to make sure that our CapEx is secured.

Maybe we -- you mentioned areas where you're seeing demand for new projects. I don't think you listed Appalachia as one of them. I don't know, I kind of think in the Trump administration, someone will take a shot at building a new greenfield Appalachia pipeline. Are there opportunities for you to increase takeaway capacity from Appalachia? And do you think someone else will also try to do it to unlock that basin?

It would make a lot of sense. I hope it happens. The federal government is definitely supportive. They've talked about supporting Constitution specifically and getting it to market. We won't proceed unless there's clear state support. The federal support is very important, and it's helpful, but you need state support in order for those facilities to get constructed. New York has been a challenge in the past. You need air permitting, water crossing permitting and without state support, that makes it very challenging.

If that materializes, and I think the current environment is one that it's been as favorable, as it's been in a long time. If it materializes, I think there are opportunities there. But that's the reason I left it off is it's -- the environment has to be favorable from a state standpoint when we haven't gotten there just yet.

Are there projects you're working on, on TGP to try to debottleneck Appalachia at all that you're considering?

There are a couple of projects that we have very early-stage development ideas on, yes.

One quick question on some of the new natural gas bills that we're starting to see. And a lot of it is [indiscernible] facilities. This is sort of an operational question. How -- from your perspective, I'm sure you've covered your cost bite take-or-pay contacts.

The first question would be, is the tariff different for a simple site or sort of a [indiscernible] facility versus [ ACGT? ]

And then the second question is back up of the line, how do they -- how are we going to handle the volume they get from [indiscernible] going through the system to make sure they're there for that 10% of the time that, that [ power plant ] works [indiscernible] storage, there not that much [indiscernible] not such a big issue about the....

We're in a really fortunate position where we're not -- usually, we're not connecting to one particular power plant. And so we're usually working with the utility to solve a grid as a whole additional gas supply need. Sometimes that does require us to connect directly to individual facilities. But generally, it's in the overall concept of this particular project, we want you to connect to these 2 facilities. But here's the contract we're going to have with Kinder Morgan.

And usually, that comes near peak, if not peak demand, which allows them to have firm supply when needed when those peakers do come on. And that's great for us because that's usually a year-round commitment at a pretty high volume level, which is great.

And then the second part...

So how do they -- is the incremental new gas fire capacity that's being built [indiscernible] right now. How are we going to -- is there enough new capacity to reason sort of operational problems [indiscernible] getting the molecules [indiscernible] because obviously, [indiscernible] and they run all the time. How do you reach that?

Well, I think that's where storage going to come into play. I think that's the next big area where we've expanded 3 of our facilities -- are expanding 3 of our facilities. We've got projects in that $10 billion. We have got couple of projects in there for additional storage development.

And so I think that's the next part of the infrastructure build out to help accommodate that an additional intermittent power generation sources in there to help with the overall relieve some of the peak needs for gas and deliverability issues for gas, the storage is going to be a key factor for that.

I wanted to ask on the Permian gas takeaway situation. We've -- well, we've just had a month where Permian gas was pricing at, I think, $1 or $2 negative, but we also have a lot of pipelines now getting built or committed to being built. Have you been surprised by how many pipelines have been sanctioned at this point? And what do you think happens to the basin? Do we get overpiped on gas takeaway out of the Permian? Or do you think it can be filled up?

Yes, I've been a little surprised by some of the pipes that are getting sanctioned. I think there are some pipes that are getting sanctioned at capacity rates that we wouldn't accept below -- well below full capacity and are just building a little bit more on spec than what we would have preferred. But there's a market demand there.

It's interesting because you're not just building it just to the Gulf Coast, but now you've got a West Coast project, potentially one going North. So yes, so I think if those projects, and I think they will get built, I think we'll see relief to the basin first. I think that probably happens maybe towards the end of the year next year as some of those bigger capacity projects come online.

And then at some point, you probably -- depending on how the gas-to-oil ratio evolves and how crude oil production evolves in the next few years, you probably have some period of time when you have adequate capacity. You see that basis spread relieve to something a lot more normal than what we're currently seeing. And again, just depending on the forward production levels of gas coming out of the Permian, you probably have adequate capacity for a handful of years.

How much demand are you seeing from the new LNG facilities that are largely in Louisiana to pull from Permian gas directly as a key supply source?

The first area for demand for those Louisiana projects is Haynesville. But you are seeing more demand for some of the gas coming across the border. And that's been a bottleneck, right? It's getting gas across the Texas border. So we're seeing it, and we've signed up a contract to support a couple of projects that we have to move gas from Texas into Louisiana. So you're starting to see it in more size, and I think that will continue to ramp up to some degree.

So [indiscernible] I'm going to say the [indiscernible] dry gas drilling [indiscernible].

It could. I first heard about that just a couple of weeks ago that, that was something that was even possible. Apparently, there is acreage that would be appropriate for some dry gas drilling out of the Permian. I think it just depends on how this gas oil ratio continues to evolve and how the overall drilling activity looks like on the black oil side to see if those projects will proceed or not.

You touched on the regulatory environment and obviously, some of the actions by the Trump administration and the FERC has obviously gotten easier to work with. What's the practical implication as it relates to some of your projects? Like are we going to see projects come on early? And what's kind of like how much is this actually improving the outlook and time frame to complete projects?

Well, the 7(c) certificate is no longer the long pole in the tent and now it's shifted the focus over to equipment availability and construction crews.

Construction crews look like they're adequately available, and we've just gone through our contracting process and our bids process, and it looked really favorable on the big 3 projects that we're going through so far. Equipment is getting a little bit tighter, particularly compression units. And so there's a longer lead time for compression units than there has been in the past.

Good news is on those projects, we're in queue. And so we put those orders in right away. And so I think we have the opportunity to bring Mississippi Crossing and South System 4 into service early. The -- how early still remains to be seen now that we've gotten pretty clear -- well, we have our clear waiver from the FERC on the 871 portion of the 7(c) certificate.

Now we are working to develop with our construction project management team, how much earlier we can bring those into service. And then what do we do with that available capacity. There's a market for it. So we'd have to go and get some interim contracts to market that capacity. But it's all good. I mean it reduces the risk to the extent that we can bring them in early, reduces that construction risk. The longer it takes you to build something, the more possible it is something can get in your way.

And then it will bring some incremental economics because of the interim capacity that we'll be able to sell. So it really will come down to how quickly we can secure the equipment needed to bring those into service.

[indiscernible] shortages or challenges that [indiscernible] impact the $10 billion [indiscernible] backlog those competing to a degree where you won't be able to secure enough time frame [indiscernible] backlog in a reasonable time frame that was too...

Yes. It's something we talked a lot about last week actually on these new projects. It's come to the point where we may end up buying some ahead of securing a project, so that we can be at least in queue. And look, a lot of our compression units across our system are getting to end of life as it is. So if we use it for a project, great. If not, we'll have other uses for those. So that's something we're taking a harder look at.

And in fact, in our 2026 budget, I expect that we'll have dollars in there for buying units just to get in queue. But it's going to be something that we will put into the construction schedule, the time frame, the backlog that we know is there today. That's what we're -- that's our starting point for how long it's going to take to secure a compression unit.

There are -- solar is a major material provider for us for these compression units, and we've been talking to them about their capabilities and their expansion opportunities.

The current view is, right now, we think that, that backlog is peaking and will actually improve based on their capacities and based on what they're seeing in the future. So hopefully, it gets better from this point, not worse, but we'll see.

Is it called [indiscernible] more broadly to the [indiscernible] for wind and sanction projects. We find that some of the peers are doing...

This has always been a pretty competitive environment. I think we're very well situated given the massive network that we have, the storage that we have on our system, our ability to secure diverse sets of supply and the ability to provide suppliers to diverse demand markets. But it's always very competitive.

And yes, we have seen some particularly newer entrants to the market get really aggressive on the return requirements. We'll continue to take our disciplined approach to it, right? We won't sanction things unless we have an adequate amount of the capacity secured at take-or-pay contracts, long-lived assets, long-lived contracts and look at that means we miss out on a project or 2, and Copper State is the one I'm pointing to, because we thought that -- that's a $5-plus billion project, and it had an adequate amount of risk to it.

So we put forth what we thought was the appropriate set of terms for our counterparties to commit to that we thought would be appropriate given the risk profile of that project, and we were out of market, and that's okay, given the opportunity set that we're looking at right now, we've got plenty of other areas to focus on.

Great. We are out of time. So we're going to end it there. David, thank you very much for joining us.

Thank you, Keith. Appreciate it.

Good morning, everyone. My name is Theresa Chen, and I'm the midstream and refining analyst here at Barclays. It is my pleasure to introduce our next company, Kinder Morgan. With us from Kinder is CEO, Kim Dang. Welcome, Kim.

Thank you. Glad to be here. It's such a great conference.

Glad to have you, as always.

Kim, I'd like to start with a discussion of Kinder's a robust outlook for natural gas infrastructure demand growth. Since we spoke at last year's conference, Kinder has increased its forecast for natural gas demand growth through the end of the decade and beyond? And can you talk more about the recent drivers of this incrementally positive outlook as well as other potential needle movers to look out for from here?

Oh, sure. So yes, we actually -- we have increased our natural gas demand forecast. I think last year, we were around 20 Bcf of growth over the next 5 years. And now we're projecting 28 Bcf a day of growth between 2025 and 2030. And historically, we have not published our own demand forecast. We typically use WoodMac. But about a year ago, we started to diverge more from where their numbers were. And then so we started publishing our own. And right now, their number is at 22. So they're a 22 Bcf a day, we're at 28 Bcf a day.

The biggest difference between those 2 is we project LNG export growth of 20 Bcf a day. And so that's a huge percentage of the 28 versus WoodMac at 15 Bcf a day. And if you look right now at the projects that are actually under construction plus 1 project that was recently FID. You're over the WoodMac number, and you're starting to approach our number. And there have been a number of SPAs that have been announced this year for projects that are not yet FID, which I think people are seeing as more and more likely.

So I actually think there's a reasonable possibility that we exceed the 20 Bcf of growth. And so the demand forecast for LNG has just continued to strengthen and especially as a result of the administration has been encouraging and has been supportive of that. We -- the other place we see big, nice demand growth is on the power side. And that's a function of multiple factors.

Obviously, the one that a lot of people focus on is the data center growth. But it's not just data center growth. It is population migration as populations have migrated south. It is businesses have moved south. You have onshoring or reshoring and so you've got chip factories in Arizona, car factories in Alabama and Georgia. All these things need power. In Texas, they're looking to back up more of the renewables. And so there's big demand for these peaker plants. And so we expect that there's going to be really nice demand for power growth.

The other thing I'd say about the power growth estimate is our projections and WoodMac's projections were done prior to the recent reconciliation bill, the 1 big, beautiful bill. And so I think there was an expectation prior to that, that there was going to be more renewable development. And now I think natural gas, predominantly will have to fill that hole. And so I think there's probably upside to what we've forecasted on the power side.

The other thing I'd say about our power projections is they are much more conservative than if you look at AI spend and what people think is going to drive how much power demand there's going to be as a result of AI spend or some people look at the GE turbine backlog and they've got a much greater number based on that. If you look at the utility all those drive bigger numbers than what we have in our forecast. So I think it is a very nice environment to be a natural gas infrastructure company. I said on our second quarter call, I've been at Kinder Morgan, approaching 25 years, and this is the best opportunity set that I've seen during my career at Kinder Morgan.

Yes. Within that extremely robust opportunity set and the outlook, Kinder has also been very busy over the past 12 months on the commercialization front. And among the major projects in the backlog intended to support this growth at Trident. I want to talk about that for a second. Okay. So recently upsized to 2 Bcf per day to satisfy incremental LNG feed gas demand. Can you talk about the strategic importance of Trident to KMI. And how should we think about the likelihood that a Phase 3 potentially would move forward? And should we anticipate more capacity from further phases to support LNG feed gas needs as well.

So for those of you who aren't as familiar, Trident is a pipeline project, which moves gas from the west side of Houston. Katy area up and around Houston, down into, what I call, LNG all on the Texas side of the border. So Port Arthur is down there and Golden Pass is down there, a lot of -- and as a result of the second phase, we are tying in to KMLP which is a Louisiana project, which moves through the Louisiana LNG alley. So we're tying tried it into KMLA so that we can further serve LNG demand on the Louisiana side of the border. So it's a $1.8 billion project can move 2 Bcf a day. And it's largely backed by LNG demand. There also is some power demand that is backing that project.

But yes, I mean, I think with the expansion opportunities that we just talked about on the LNG side, the 20 Bcf a day growth, there's going to be nice opportunities to potentially expand that pipe. We serve about today, 45% of -- or move 45% of the gas going to LNG facilities. And right now, we've got about 8 Bcf a day contracted. That will go to 12 Bcf a day based on Trident and some other projects where we have signed contracts. And so it's just -- it will be a great opportunity for us to build off of in the future. So looking forward to potential opportunities there.

Got it. and tackling the LNG feed gas from a different angle. Okay. So now that you would expect to transport 11 Bcf per day of LNG feed gas by the end of 2027. So given the LNG-related project authorizations have continued to accelerate under the current administration, how can Kinder position itself, particularly within the Haynesville to capture greater market share within LNG feed gas going forward and potentially bring upside to this estimate of 11.

So we've got, in addition to the interstate and intrastate pipes that we have to serve LNG. We've got a big position gathering and processing position in the Haynesville. Our projections is that the Haynesville is going to need to grow by about 10 Bcf a day to meet the demand forecast that we have I think if you look at WoodMac forecast there at 6 Bcf a day. So either way, significant growth coming off of what is about 13 Bcf a day of production in the Haynesville. We just announced in the second quarter a $500 million investment in our gathering KinderHawk in the Haynesville that's going to add 1 Bcf a day of processing capacity. It's going to add pipe capacity. We've already started to see the producers in the Haynesville start to ramp their production. Projections are for the fourth quarter that LNG demand is going to 19 Bcf a day. And so we're going to see some pretty significant increases in LNG demand over the next several months. And I think KinderHawk is well positioned to meet that now and then as we expand it into the future.

Got it. And I want to also talk about the Texas Access project. which aims to utilize KMLP to deliver gas off of Trident into South Louisiana further supporting your LNG feed gas strategy. How does this fit in within your overall footprint and strategy? And what are the growth opportunities along this.

Sure. So interestingly, KMLP was originally built to import natural gas. And so when we thought -- the country thought we were going to run out of natural gas. It was built to import for a couple of major oil companies. Now we have turned that pipe around and using it to export. So as I mentioned earlier, it ties in to Trident, so we can move gas from the Katy area so that would be Haynesville gas -- I mean that would be Permian gas and Eagle Ford gas. We can move over into the LNG corridor by using Trident flowing into KMLP.

KMLP goes from the coast, and it goes up into what I call pipeline alley. So it interconnects with all kinds of interstate natural gas pipelines. So you can actually move gas into those facilities from all those connections. And now we'll be able to move gas in there coming from the Texas direction as well. So it can be multidirectional. So it's going to be -- it's going to provide us a lot of flexibility to serve those export LNG. And there's pretty cheap expansibility of that pipe. Right now, we have about 1 Bcf of that subscribed with the most recent project. But there's another 1 Bcf and maybe more of expansion capacity that we can do very economically on that pipe.

Great. And aside from LNG feed gas, which is the primary driver of near-term growth, of course, to your earlier point, Kim, power generation is another major contributor to the positive outlook for gas infrastructure, in part, supported by the anticipated proliferation of data centers to come. So now that the proposed copper state connector is unlikely to move forward following the sanctioning of a competing project, could you provide color on other major project opportunities that Kinder is currently assessing to support the growing gas to power load and where are KMI's competitive advantages in winning these potential projects.

Yes. I mean I think I'll just start with the competitive advantage. I mean we've got a huge natural gas system. So if you look at the design capacity of our interstate natural gas projects, I mean, interstate natural gas pipelines, it's like 63 Bcf a day. I mean, so we've got a huge system that we can then build off of. And so that makes expansion opportunities very economic generally. And allows us to offer our shippers a lot of different services in order to meet their needs. So that's where we get a lot of competitive advantage.

I mean I think other places is we're in this business for the long haul. So when we build pipeline projects, we want to make sure that they are going to work for the long haul and serve our customer needs. And I think generally reviewed as a very good operator. So I think all those things work together to help us win those projects. But in terms of the opportunity set that we see today. And this is overall, not just on power, but I'd say a big portion of this is related to power.

Back in the first quarter of 2024, we said that we had an opportunity set. So projects that we were looking at that were not in the backlog at that time of $7 billion to $11 billion. right? And since that time, our backlog has grown from $3 billion to $9.3 billion. We've actually added like $8.5 billion of projects, put $2.2 billion in service. That's how you get to that out of $6.3 billion that we've added to our backlog. And then obviously, we weren't successful on Copper state.

So we went back and we said, all right, what does the opportunity set look like now. And so when we went across the businesses and looked at the opportunity set, the opportunity set is still in that $7 billion to $11 billion range even though we have added all these projects. So I think as we -- as you noted at the start, the demand for natural gas has continued to increase and gotten better and the opportunity set has not diminished. So I think we've got lots of opportunity in power. Right now, our $9.3 billion backlog, about 50% of that is associated with power.

And I think the one thing people miss everybody is so excited about AI and data center demand, and there's definitely going to be a lot of that. But there are so many other power opportunities out there. Our South System 4 expansion that we did -- some of that may be data center, but a lot of it is not data center. A lot of it is just growth in power demand as a result of the factors that I talked about earlier.

We are -- we've got power expansions, coal conversions for TBA that we're working on. You've got new power plants being built in Arkansas. You've got new power plants being built up north that we pursue -- that we've got projects on NGPL. And then I think you'll see some other power plant conversions in Arizona that probably can't be served with the Transwestern expansion. So I think there's enormous opportunity on the power side. But our opportunity set, despite the fact that we've added all these projects is not diminished.

Fascinating. With the steadily increasing demand for transmission infrastructure across the U.S., to your point, do you expect returns to trend higher from here? I mean even just looking at that $9.3 billion sanctioned backlog, can you tell us about the economics that you've observed have evolved? And from a regional perspective, where do you think the most attractive returns are?

Okay. So here's what I'd say on that. Almost every project that we do is competitive. And so we are always almost -- unless you're building like a 5-mile lateral off an existing pipe, you are almost always in a competitive environment and especially on greenfield projects. And so I don't anticipate that returns are going to move up from here. But I would also say that the returns that we get are very attractive. As you know, the $9.3 billion that we have in our backlog is coming at less than a 6x multiple when you look at first year EBITDA. So I mean, very, very attractive projects.

So I think we are happy with those returns and happy to do all the projects that we can get at those types of returns. And given the amount of prospects out there, I think we will continue to be able to do projects at those returns, but I don't see returns increasing. When you think about where we get our -- the better returns, I'd say the greenfield projects are very competitive. I'd say, on some of the brownfield projects, that's probably where we get a little bit higher returns.

And then we also target higher returns on like a gathering and processing opportunity. So it's always about balancing the risk and reward making sure that if we're taking more risk, we're getting more return. But at the end of the day, what we're trying to do with our backlog of projects is deliver high-quality growth to our investors. And the goal is we try to keep our base business relatively flat and then deliver nice growth from these expansion projects, which we are funding with internally generated cash flow. So there's not incremental interest or dividend costs associated with financing these projects.

Got it. We spend over half the time on natural gas. Turning to maybe the less sexy part of the business but equally important in cash yielding. On the liquids side of things. So Tell us about how these assets fit within your portfolio? And also from the lens of commodity exposure, obviously, on the natural gas side, very minimal commodity exposure, if any. On the liquid side, there is a little bit more sensitivity to crude price, which this year has beared some volatility. How do you see that evolving going forward? And would just left to get your thoughts here?

Okay. So that's good. Your first point is how do they fit within our portfolio and your second question is about commodity exposure. So in terms of how they fit within the portfolio, so if you look at how Kinder Morgan assets break down, 65% of our portfolio is in natural gas, about 26% of our portfolio is in refined products, about 9% of our business is in CO2/energy transition. So we are very comfortable with that portfolio of assets over the time that I've spent in the business. at different times, different sets of assets have had the biggest growth opportunities. And right now, that opportunity set is in natural gas.

And 1 thing that's great is it happens to be the biggest asset, the biggest asset type in our portfolio. So that works out well for us. In terms of the other businesses, the refined products businesses are very stable assets. We get inflation adjustor, a price adjustment on those annually through on the pipeline, through the pipeline tariff. And if you look at our contracts on the terminal side, generally, those contracts have escalators built into them. So you have some nice inherent growth built in tool they're relatively low in terms of capital intensity, so they deliver a lot of cash flow to our business that we can use to finance the growth in natural gas.

And on the CO2 assets, we get great returns. We target good returns. So there where you have a little commodity exposure, we're targeting to get 20%-plus returns on that business. we look at those returns on all the projects that we're doing with our Board every quarter. And most of those projects are exceeding 30%. So we're getting very attractive returns where we are taking commodity risk. We think that is that's compensating us for the additional risk that we're taking. So very comfortable with that portfolio of assets. That being said, we are economic creatures. And so every business that we have is for sale every day.

And if we get the right price for an asset, we will sell it. We will make the right economic decision. But there are tax consequences to selling assets, and so we have to overcome those tax consequences for it to be the right economic transaction for us. And you say, well, how does that happen? I mean there are places where we found that assets that we've had in the past were better owned by someone else, where they had more synergies or could get more out of the assets because of other assets that they own. And so we've sold assets in the past, not averse to doing it, just need to make sure that we get the right economic results from that.

And then on commodity price exposure, you looked the way our business breaks down, about 64% of our EBITDA is from take-or-pay contracts, meaning that our customers pay whether or not they use the capacity. Now in the long term, we want them to use that capacity because that means they'll renew their contracts when they roll in 10 years. But in the short term, if there are fluctuations in demand, it just -- it's not a big deal for us. 26% of our business is fee-based, meaning that there's no variation in the price we receive. There's some fluctuation in volume. But a lot of that volume on that is associated with refined products, which is pretty stable. And then 10% of our business is exposed to commodity price. Most of that's in CO2, so it's exposed to oil price. And then some of that is in our natural gas gathering and processing business.

On the CO2 side, we hedge a good portion of that in any current year. So when you look in the current year, we only have really 5% of our business is exposed to commodity prices because we hedged the other 5%. So I think given the nature of the cash flow on the rest of our business, the scale and the scope of the business, the balance sheet flexibility we maintain I would put this set of assets up against most others. I mean, it's a really nice set of assets that we own, a really stable business.

The one thing I'd say about volatility is it also presents opportunity for us. So the services that we provide and especially natural gas volatility because of the services that we provide our natural gas customers. And so when you get big volatility in gas prices because you're getting change in supply or demand, we can provide storage services for our customers. So we can provide what we call synthetic storage, which is parking loan on our pipes. And so there's -- we can provide balancing services. So there's a whole host of incremental services and ancillary services. that when you see volatility in supplier demand, we provide for our customers and bring us incremental revenue.

Thank you for that comprehensive answer. I do want to touch on the CO2 segment and how you see the future for the segment evolving. So on one hand, the recently tested OBBA includes tax incentives to support EOR activities. However, elsewhere in the segment, the RNG business has faced intermittent operational challenges as the facilities have come online, plus headwinds due to lackluster D3 RIN prices. So how do you view the path forward for the CO2 segment?

So CO2, obviously, we talked about the oil & gas business, the returns that we get there. And we have -- there aren't a lot of players in the CO2 business. And so we've got a -- and we've got an expertise in a business that a lot of people don't understand. And so we're continuing to invest in CO2, where we can -- the CO2 oil and gas production, where we can get returns. And then we have optionality, if you will, on CCS or CCUS, so carbon capture. You noted that the reset OBBA took the tax credits that you can get on CCUS, so capturing carbon injecting it for EOR and then producing oil from $65 to $85. So it makes more of those projects economic.

And so that will -- that presents additional opportunities for us. But it's nice that we've got the staff of engineer reservoir engineers they know how to keep CO2 in a certain area. So for example, we had a field onetime where we are injecting CO2 to produce the oil and the CO2 started migrating to someone else's field. where we know how to install water curtains to keep it within that field. So now when somebody else wants to do it in their field or just sequester it permanently. We have the expertise to do that, not many people do. So we've got an existing business. We have those reservoir engineers on staff. We're keeping them busy on our CO2 business.

But -- so we're not incurring a lot of overhead to have the optionality on the CCS and the CCUS business. So I think it's -- it's a great place to be. That business is going to take time to develop. I think it slowed down a little bit under the current administration. But I think there'll be opportunities in the future there. On the RNG business, it's something that's -- it's -- you noted that RINs prices have come down. That makes new investment opportunities less economic. So I don't see it as a business that will be expanding a lot in the next -- or during the current administration.

But it's a fine business. We have had our operational challenges, but I think we're getting to a point that we're getting those facilities running much more smoothly. And so it will be a fine business for us to stay in, and then we can see what happens after this. But I think -- in general, this administration has been hugely positive to the natural gas business. And everything we're seeing there, which is 65% a little bit of headwinds on the RNG business, which is less than 1% of our business. So we'll take that equation any day.

Fair enough. And finally, I'd like to discuss Kinder's capital allocation priorities from here. With this lengthy runway of potential gas infrastructure projects. Would you consider increasing run rate CapEx above the $2.5 billion run rate over the next few years to support more growth opportunities. And how do you plan to balance growth in general versus maintaining comfortable leverage and returning cash to shareholders?

Okay. Let me say a couple of things about that. So for those of you who aren't as familiar, what we've guided is we have roughly $2.5 billion per year of expansion. CapEx opportunities, which we can fund based on what we pay out in the dividend and $2.5 billion we can fund with internally generated cash flow. And so it's -- $2.5 billion is a rough number in any given year, that can be up or down from that just depending on how the project spend rolls out on the $9.3 billion backlog. If it's more than that, we've got balance sheet flexibility. Right now, our leverage, our debt-to-EBITDA is 3.9x. Our balance sheet range that we try to maintain is 3.5 to 4.5x debt to EBITDA. So we're in the middle, slightly on the lower end of that range. So we've got flexibility there to take on more expansion.

And if you look at the projects coming online that we're doing and what happens to leverage based on the $9.3 billion backlog, leverage trends down over time. And so what that's doing is that's just creating more balance sheet flexibility for us in the future to add projects. So we've already got some balance sheet flexibility to do incremental projects. We're adding more flexibility over time. Our view is for the projects that we're pursuing at the returns that we're getting, if we ever needed external capital to finance those, I mean, we could do that.

And as opposed to missing an opportunity, you get -- you do a JV, you get 50%. I mean there's lots of ways to cut that. I don't think we're anywhere near having those conversations just because of the balance sheet capacity that we do have. And I expect that we'll continue to add to the $9.3 billion backlog given the demand in natural gas growth. On the dividend side, I think what you'll see us pursue is similar to what we've done over the last few years, we want to grow the dividend by some amount, but it keeps it fairly modest given the opportunity set that we see out there. So I think it's important for those people who are owning our stock for dividends. to show some growth, but at the same time, we want to maintain flexibility given the current environment in which we find ourselves.

Excellent. Thank you so much, Kim.

Good afternoon, and thank you for standing by, and welcome to the quarterly earnings conference call. [Operator Instructions] Today's conference is being recorded. If you have any objections, you may disconnect at this time. It is now my pleasure to turn the call over to Mr. Rich Kinder, Executive Chairman of Kinder Morgan. Sir, you may begin.

Thank you, Michelle. Before we begin, as usual, I'd like to remind you that KMI's earnings release today and this call include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 and the Securities Exchange Act of 1934. -- as well as certain non-GAAP financial measures. Before making any investment decision, we strongly encourage you to read our full disclosures on forward-looking statements and use of non-GAAP financial measures set forth at the end of our earnings release as well as review our latest filings with the SEC for important material assumptions, expectations and risk factors that may cause actual results to differ materially from those anticipated and described in such forward-looking statements. In previous quarterly calls, I've emphasized the positive attributes of the natural gas story, concentrating primarily on the rapidly growing demand in America. But as we all know, the gas market is international in nature and a great deal of the growth potential for U.S. production is driven by that worldwide increase in demand.

So I thought today, I would spend a bit of time sharing some thoughts on what's driving that overseas growth. Chief Economist of a major oil company recently estimated that global gas demand is expected to increase by 25% over the next 25 years. And I don't believe that, that projection is unreasonable and it affirms my belief that natural gas will inevitably remain a key source of energy for the long term around the globe. The factors underpinning that growth are pretty easy to understand. Demographers project continued substantial growth in worldwide population over that time period in the range of 2 billion additions by 2050. A great bulk of that increase will occur in the emerging markets of Asia and Africa. where the need for energy is particularly acute as large portions of the population move into the middle class, which drives additional energy consumption. Because there is a lack of local production and an inability to access gas by land-based delivery in most of those nations, it will be LNG, which will satisfy the bulk of this additional demand, and I think it will grow faster than the overall demand for natural gas. Now what's the impact of all this international growth on the U.S. Energy segment? I believe that American exports of LNG will play a critical role in supplying this international LNG demand.

The U.S. has been the top global producer of natural gas for 15 consecutive years and the world's top exporter of LNG since 2023. I believe the U.S. role becomes even more important in light of recent developments in the Middle East. Customers on the receiving end want security of supply without undue worries about disruptions caused by military actions, and this benefits the position of U.S. supply. This makes us confident that a major portion of the LNG required will move through America's rapidly growing liquefaction terminals. Consistent with this view is the recent estimate of S&P Global Commodity Insights that LNG feed gas demand in America will increase by 3.5 Bcf a day this summer compared to summer of 2024 and that it will more than double by 2030. That should be a real positive for Kinder Morgan in as much as we move about 40% of all the feed gas for those facilities. When you add the international LNG growth to the robust need for gas to satisfy U.S. domestic power and industrial demand, examples of which are reflected in the new expansions that Kim and the team will be discussing on this call, it signals to me that the positive natural gas story has legs and will last for decades to come. With that, I'll turn it over to Kim and the team.

Okay. Thanks, Rich. Our financial results for the quarter show strong growth over the second quarter of '24 with adjusted EBITDA increasing by 6% and adjusted EPS increasing by 12%. For the year, we currently expect to exceed our original budget, which already reflected very nice growth by at least the contribution from the Outrker acquisition. It's an amazing time to be in the natural gas industry. This is certainly the best opportunity set I've seen during my 24 years in this industry. The underlying market fundamentals are strong with U.S. natural gas demand expected to grow by 20% between now and 2030 by WoodMac estimates. The federal permitting environment has improved. The U.S. Army Corps of Engineers is issuing permits very quickly. We've seen some recent FERC action, which is helpful, including a 50% increase in the prior notice limit and a 1-year waiver of the 5-month waiting period between the time -- before you can start construction -- between the time the permit is issued and you can start construction. So the Supreme Court ruling on NEPA should help narrow the scope of the NEPA reviews and make nuisance lawsuits more difficult. The recent budget reconciliation bill delivers nice tax benefit, including incentives for investment and expanded interest deduction. As a result, we expect significant cash tax benefits in 2026 and 2027 and do not expect KMI to be a material cash taxpayer until 2028.

The one fly in the ointment is tariffs. However, at this point, we still do not believe that the tariffs will have a significant impact on project economics. For our large projects, MSX, South System 4, Trident, GCX and Bridge that together comprise almost 2/3 of our backlog, we currently estimate that the impact of tariffs to be roughly 1% of project cost, which has not changed from our estimate last quarter. Our project backlog increased from $8.8 billion to $9.3 billion during the quarter. We added $1.3 billion in new projects and placed approximately $750 million of projects in service. The projects we added included Trident Phase 2 and the Louisiana Line Texas Access project, which include moving natural gas from Katy, Texas into the Louisiana LNG market. We also added 2 NGPL projects to serve power plants. All these projects are underpinned by long-term contracts and have attractive returns. We also approved approximately $500 million of CapEx for KinderHawk, which is supported by life of lease contracts to accommodate a significant volume ramp-up by our customers. Currently, approximately 50% of the projects in our backlog will serve power demand.

The multiple on the backlog is around 5.6x, slightly improved from Q1 as the projects we placed in service were at a lower -- that we placed in the backlog were at a lower multiple than the projects we placed in service. Overall, despite $6 billion in project additions to our backlog in the past year, we continue to see very nice future investment opportunities. As Tom Martin said to me the other day, we aren't in the first inning anymore, but we are anywhere near the seventh inning stretch. Our strategy remains unchanged. We own and operate stable fee-based assets, which are core to the energy infrastructure. We use our significant cash flow generated by these assets to invest in attractive return projects, and we return money to our shareholders, all while maintaining a solid balance sheet. With that, I'll turn it over to Tom.

Thanks, Kim. Starting with the Natural Gas business unit. Transport volumes were up 3% in the quarter versus the second quarter of 2024, primarily due to LNG deliveries on Tennessee Gas Pipeline as well as new contracts and LNG deliveries on our Texas Intrastate system. Natural gas gathering volumes were down 6% in the quarter versus second quarter of '24 across most of our G&P assets, the biggest impact being in our Haynesville system. Sequentially, total gathering volumes were down 1%. Our one -- our producer customers are still ramping back up after lower gas prices in the second half of 2024.

For the full year, we expect our gathering volumes to average 3% above 2024, but 3% below our '25 budget. We anticipate gathering volumes will grow over the balance of the year given the higher price environment than in 2024 and the need for increased production to meet LNG demand growth that is ramping up throughout the remainder of the year. Looking forward, we continue to see significant incremental project opportunities across our natural gas pipeline network to expand our transportation and storage capabilities in support of the growing natural gas market. In our Products Pipeline segment, refined products volumes were up 2% and crude and condensate volumes were also up 2% in the quarter compared to the second quarter of 2024. For the full year 2025, refined products volumes are forecasted to be approximately 2% higher than in 2024 and flat to our budget. In our Terminals business segment, our liquids lease capacity remains high at 94%. Market conditions continue to remain supportive of strong rates and high utilization at our key hubs at Houston Ship Channel and the New York Harbor.

Our Jones Act tanker fleet is fully leased today and through the remainder of 2025. Assuming likely options are exercised, the fleet is 100% leased through 2026. and 97% leased through 2027. We have opportunistically chartered a significant percentage of the fleet at higher market rates and have extended the average length of our firm cotton contract commitments to 4 years. The CO2 segment experienced slightly lower oil production volumes at 3%, higher NGL volumes at 13% and lower CO2 volumes at 8% in the quarter versus second quarter of 2024. For the full year, oil volumes are forecasted to be 4% below 2024 and 1% below our 2025 budget. With that, I'll turn it over to David.

Okay. So we're declaring a dividend for the quarter of $0.2925 per share, which is $1.17 per share annualized and 2% up from our 2024 dividend. For the quarter, we generated net income attributable to KMI of $715 million, which is 24% above the second quarter of 2024. We generated EPS of $0.32, up $0.06 from last year. Some of that benefit was due to favorable mark-to-market on unsettled hedges, which we treated certain items. But on an adjusted net income basis, which excludes certain items, we generated $619 million and adjusted EPS of $0.28, up 13% and 12% from last year, respectively.

So even excluding the favorable certain items, we still experienced nice double-digit growth from last year. Our growth was driven by greater contributions from our natural gas expansion projects, the Outrigger acquisition and attractive multiple -- excuse me, attractive natural gas capacity sales and other services, driven by favorable demand on our assets. We also received greater contributions from our Jones Act tankers. On the balance sheet, we ended the quarter with $32.3 billion of net debt and a 4.0x net debt to adjusted EBITDA ratio. That 4.0x is down from 4.1x from the first quarter, which was right after we closed the acquisition of Outrigger. We expect to end the year with net debt to adjusted EBITDA that rounds up to 3.9x. Our net debt has increased by $623 million from the beginning of the year, and here is a high-level reconciliation of that change. We generated cash flow from operations of $2.811 billion for the first 2 quarters. We paid dividends of $1.3 billion. We've invested total capital of $1.42 billion. The Outrigger acquisition was approximately $650 million, and all of our other items were a use of cash of about $65 million, and that gets you to the $623 million increase for the year.

As Kim mentioned, we expect to exceed budget by at least the contribution from the Outrigger acquisition. Our budgeted 2025 adjusted EBITDA growth from '24 was 4%. Just including the Outrigger acquisition, our EBITDA growth would increase to 5%, and our adjusted EPS growth would remain at an attractive 10% from 2024. Most of our 2025 budgeted growth comes from expansion project contributions, and we remain on target to place those expansion projects in service on time and on budget with only minor variances. The largest expansion contributions come from Evangeline Pass project and our South Texas to Houston project, our Texas Intrastate system. Both of those are now in service. So in my final items, in June, Moody's placed our credit rating on positive outlook, and they joined S&P who put us on positive earlier in the year. Our credit spreads have already improved some as a result. So we're off to a good start for the year tracking to beat our budget. We've sanctioned additional attractive projects that will add to our future growth and expect meaningful cash flow benefits from tax reform. I'll turn it back to Kim for Q&A.

Okay. Michelle, if you'll come back on, and we will take questions.

[Operator Instructions] Theresa Chen with Barclays.

Congratulations on the progress in the commercial backlog under what seems to be fierce competition. Do you think the commercial landscape has changed with these demand tailwinds on a structural basis? And what do you think has allowed Kinder to win many of these projects? And what kind of learnings can you share that might shape your strategy going forward on the heels of these commercial wins?

Okay. A couple of points on that. One, I think what -- part of what allows us to be competitive is the existing asset footprint that we have. We've got an outstanding footprint. And so we are very competitive where we can build off of that footprint and/or use the existing footprint to deliver volumes to customers. I'd say the other things are, I think people trust us to be able to build projects and get them delivered. And so if they've got a significant investment that they need natural gas delivered, they don't want to be waiting on those molecules.

When they get that project in service, they want to be able to have the supply there. So I think our track record in building and delivering projects is helpful. And then I think the way we operate and the customer service that we provide in terms of trying to make sure that if we have maintenance or other items that our customers need to know well in advance, trying to make sure that we perform that maintenance at times when our customers would be least impacted and trying to find times when our customers when we can find alternative delivery for them. So I think that's some of the things that go into the commercial discussions and allow us to win projects. And I think as you can see from what we've added to the backlog, we've been very successful.

And looking forward on additional projects to come potentially in the backlog. As far as the expansion of Westwood from the Permian, what is the progress on building additional natural gas infrastructure on that front? And what would something like copper state connector amount to in terms of cost economics as well as the potential for subsequent brownfield expansions down the line?

Okay. Well, let's not get too far ahead of ourselves. On Copper State, there's clearly a need in Arizona. I think the utilities have need for more natural gas. I think there's the potential for data centers, and we're having conversations on those fronts. Obviously, that would be a large project. There are other Copper State wood. I mean there are other smaller projects that we have that we're looking at. but it is a competitive process on copper state and constantly changing tariffs make things more challenging on these larger projects where we've got to come to agreement with multiple different shippers.

And then any project that we do on this front, the project is going to have to meet our return thresholds. And so we're going to be very disciplined about how we deploy capital on this. But I mean, a project could be anywhere from $4 billion to $5 billion-ish.

Our next caller is Michael Blum with Wells Fargo.

How do a capital allocation question really between gas pipelines and gathering investments. You talked about this big opportunity set on the gas pipeline side. Your average multiple is between 5 and 6x. So how do we think about a $500 million investment in KinderHawk? Does that mean this change on investment is generating an even higher return than that given the higher risk profile? Just kind of things all that.

Okay. Sure. So let me start by saying no change in the way that we make our investment decisions or in our approach to investment or investment returns. The way we've always done it is we look at the risk reward. So you're looking at -- on the risk side, you're looking at how stable are the cash flows. And so that gets into, okay, is it a take-or-pay contract? Or is it a life of lease dedication.

Does it have -- if it's a take-or-pay, is it a 5-year contract? Or is it a 20-year contract? What's the credit on that? And so when you have longer contracts with higher creditworthy partners, and their take-or-pay, then within our return threshold range, you're going to skew to the lower side of that range. And when you have things that have commodity exposure or volume exposure, then you're going to look for a return at the higher end of our target range.

Okay. Great. And then I just want to see an update how you're thinking about behind-the-meter opportunities. I know you've talked about maybe having something in place with partners or -- so wanted to see where that stands and how meaningful a driver of future CapEx that could be?

So I think when we think about where we've seen the most action on the data center front, if you will, is really from regulated utilities. I mean that's where we're seeing most stuff get done. So a regulated utility is able to put it in their rate base. They're going out and they're getting a PPA with the data center provider. We have not seen a lot of IPPs that have announced projects at this point in time. But obviously, we are talking to them, and that is -- that's a reasonable possibility because I think if IPPs can get contracts, they'll be able to build as well. But I'm going to turn it over to Sital and he can talk a little bit more about our strategy there.

Yes. So one of the things, as we look at the landscape on data centers, speed to market is key. And so as we look at the opportunity set, as Kim said, our focus has thus far been on the utility side and helping them with their power needs. We are looking at kind of a broader structure such as where we've got some key partners that specialize in their respective fields. Our expertise lies in bringing supply to the point. We bring storage and then we let the other folks do what they do best, including hyperscalers that know how to build data centers.

And so I think the concept is we are looking at a few key sites in different areas and seeing if we can kind of pull together a bigger, broader project, specifically tied to behind the meter.

Our next caller is John Mackay with Goldman Sachs.

Going to pick up on this project thread, of course, maybe just talking about the backlog on the gas side. You mentioned about 50% power utilities at this point. That's arguably a larger share than power has and kind of the go-forward gas demand growth we're looking at relative to LNG, I suppose. Maybe could you just talk a little bit about how you'd expect that 50% to kind of trend from here? Would incremental projects on the horizon, maybe putting aside copper state for a second, start leaning more LNG, I mean we need to wait more FIDs. Maybe just frame up like how that mix looks over the next couple of quarters or years?

Yes. I mean I'd say it's hard to project exactly what that mix is going to look like. Obviously, the biggest driver of demand growth, both in WoodMac's projections and in our internal projections is LNG, and there's a doubling of -- expected doubling of LNG. As we've said a number of times, those LNG projects, I mean, generally, when they get sanctioned, there's an initial project that is sort of a mainline from the facility to the nearest liquid point. But then generally, as they move forward with their development, they're looking to find more competitive supply and diversified supply. And so that leads to additional projects, additional projects down the line.

One of the things that we've consistently said and that we consistently see is -- and this is especially true in the WoodMac numbers is we don't think that the Wood Mac numbers accurately reflect the growth that we think we're going to see in power demand. And that could be a difference between the volumes that they expect to flow and what we expect to sign up in terms of long-term take-or-pay contracts. But the demand, the breadth and the scope of the power demand is very enormous. And so I mean, we're seeing power demand in Arkansas, Louisiana, Georgia, South Carolina, Arizona, Wisconsin, I mean, Texas. And so -- I mean, the amount of power demand, I think, and the projects that we're going to see on that front are -- when you look at that relative to the expectations for demand in power, I just think there is an alignment there.

That's helpful. That's a good thing. And maybe for my next question, you come on the new tax rules should open up some incremental cash flow for you guys. I guess just wondering if you can kind of put a bit of a number around the incremental cash kind of looking forward. And then on a related point, does it change how you think about your ability to go after projects your kind of implicit cost of capital? I know you're kind of defending the return profile you want to get, but does an incremental tax framework change that at all?

John, it's David. For the tax reform benefit, we're not quantifying it any more specifically than just saying we've got nice benefits from it beginning in 2025. It's not material in 2025 to our forecast, but we'll see some benefits this year because it was retroactive to the beginning of the year. We are seeing substantial benefits in '26 and '27. So as Kim said, we don't expect to be a material federal income taxpayer in either of those years as a result of the tax reform. We see nice benefits there after, but we're not quantifying those. And it also depends a little bit on when we put new projects into service because the full expensing provision is really the biggest piece of the benefit that we're getting from tax reform.

And I would say having that incremental cash flow doesn't change our investment strategy. So we're not moving our return thresholds because we have incremental cash flow available. I think our view is and continues to be that for good return projects, there's unlimited capital, and we will find a way to finance them. So Obviously, we've got a lot of cash flow available more now than we did before. We've got room on our balance sheet. And I think with the projects that we're doing, they're attractive projects. And so if we ever needed to, we can bring in outside capital.

Our next caller is Jeremy Tonet with JPMorgan.

Want to turn to Arkansas, if I could. We've seen recent reports of hyperscaler activity there and I want to double click on your Texas, Arkansas Power project. Noticed a binding open season there and given the 400 already prearranged there, it seems like that could support 2 gigs, very nice size for the project right there. But do you expect more to come along at that point? Do you see the possibility for more demand beyond that? Or really, you kind of have a fit-for-purpose pipe rate here and ready to go? And anything you could provide as far as incremental details there would be helpful.

Yes, Jeremy, this is Sital. So I'll back space on that and tell you that it's -- that project is supporting power. But broadly, when you think about the opportunity set, we are seeing incremental opportunity set not only in Arkansas, Texas, but along the that Midwest corridor. We do see incremental demand on the power side, where the utility ultimately uses it. That will be up to the utility. As we talked about, we're looking at our own behind the meter opportunities. And so I think there is a robust pipeline of opportunities that we are trying to pursue, specifically in Arkansas and really broader across the network.

And I'd say we don't always know if the power is going to a data center or what exactly so that they're using it for. So we don't always have clear visibility through -- our customer is typically the power -- is typically the power plant.

Right, right. Understood. Just the size of it there, it could support some nice power for the utility, not for Kinder, understood there. But I'll leave that there. And just wondering, post the Georgia Power IRP filing here, does this impact, I think, the opportunity set as you see it in the Southeast? Could there be upside, I guess, to your current expansion plan scope to make those expansions larger?

Yes. Look, I mean, as we've alluded to on previous calls, I think there is a broader opportunity set. We're early in our discussions there. But the fundamentals look sound and the opportunity set looks good. Obviously, we're positioned well with the network there, including the latest set of expansions. And as we alluded to on the last call, I think Rich said, we've got ancillary expansion opportunities to layer on top of that, we will pursue those as they present themselves.

Manav Gupta with UBS.

It looks like you have increased the size of Trident from 1.5 to 2 Bcf. And as I remember, you did this with Mississippi Crossings also the pipe got announced at 1.5 and got scaled up very quickly to 2.1 million. I'm trying to understand what's driving this incremental demand. You come in, you announce a project and very quickly, you're able to size it up so help us talk through those dynamics a little.

Yes. I mean on Trident, the incremental demand is associated with LNG. And it was a fairly easy expansion because there, all we needed to do was add some compression. I think when you go to a Phase II, then that would require some looping. So that's a little bit that's a little bit bigger nugget to take on. And so that would require more volume to do Phase II. But that pipeline is in a great, great location and to be able to get molecules from Texas all the way over into Louisiana is something people have been trying to do for a long time. And the combination of Trident and KMLA does that.

Yes. In terms of the timing piece, Manav, I mean, really, it's when we get the executed contracts to get us the returns that are sufficient. We know we have other customers that are interested we will FID the project if it makes sense, and then we continue to try and build upon it. That's been the strategy.

Perfect. And it looks like the backlog also benefited from the NGPL new projects. Can you talk about -- a little more about these projects? It looks like the power plant-related projects. So if you could help us understand that this incremental projects from NGPL that added to the backlog in this quarter?

Yes, they're both power projects to serve power demand, one in Arkansas, one in Wisconsin essentially.

Yes. That's probably all we can tell you at this point.

Our next caller is Jean Ann Salisbury with Bank of America.

I just wanted to follow up to Kim's answer to John's question earlier about when LNG projects sign up for their gas pipeline needs vis-a-vis when they get sanctioned. You've obviously had a ton of LNG contracting activity over the last quarter. I think you're probably still to come this sort of large wave of sanctioning. So I guess my question is if you believe that those projects have kind of already signed up for the gas takeaway that they would need or if that's basically coming as the sanction of the projects over the next year?

Generally, what we see, and Sital will jump in here, is that when a project gets to get a project in FID, they need to get their financing and put their financing in place. And so to put that financing in place usually they've got to have a gas supply. And so that's when the initial project, as I'll call it, from the facility to the nearest liquid point gets sanctioned. And then generally, what happens after that is as they continue and they're starting to get closer to in-service.

They decide, okay, and they're thinking about really how am I going to supply this on a daily basis. Then they start looking at, okay, that liquid point is very competitively priced. I might want to get some cheaper molecules and/or what happens if a pipe goes down or something, maybe I also need some diversification. So that happens more over time between the time the project gets sanctioned and before it gets put in service.

And let me just add to what Kim says that given the fact that this demand is occurring primarily along the Gulf Coast, where our system is so extensive. This kind of opportunity just lends itself to a structure like we have. I think we cannot overemphasize the benefit that we have from the infrastructure that already exists and the ability to expand it on a reasonable basis.

That's very clear. And then as a follow-up, I wanted to ask about some of the dynamics of Permian gas pipelines. We're very tight on egress capacity today, but something like 5 Bcf/d comes online next year, including your own GCX expansion. And I think there are a few other possible projects out of the Permian that seem to be progressing. So I guess the question is, if there's some concern that this could put pressure on rates for Kinder Morgan later in the decade if some of those initial pipeline contracts begin to roll off. Can you just kind of talk about how you would frame that risk of Permian overbuild?

Sure. So the GCX and PHP are 2, I think those 10-year contracts expire in '29 and '30. What I would say is given that those were some of the first pipelines built out of the Permian to the Gulf Coast, they have very attractive rates on them. And so 2 things. One is, I think they are lower rates than where new projects are getting priced. So there's going to be some of the cheaper transport out of there. And then the -- I forgot what the second point I was going to make. But Sital, go ahead.

Yes. So I mean, the other thing, as we think about the 2 pipes that we have, if you're talking about kind of recontracting risk, et cetera, those pipelines fit very well in our network, and we have the ability to extract probably, in my view, better values once those -- if those aren't recontracted. And so we view that risk is low. When we think about the X project out of the basin, we're going to be very prudent as we think about our focus has shifted to demand pull when you think about the projects that we sanctioned over the last couple of quarters. So if there is another producer-push project, it would obviously have to be very well contracted and for a longer term.

So those pipes go into our Texas intrastate system. They feed contracts that we have in the Austin market. So we have in-use demand attached to that, and that's something that we can offer shoppers and customers that other people can offer. And then the other thing I was going to say is that when we run our economics in order to be conservative to make sure we get good returns on these projects, we assume generally, we assume a step down in rates whenever contracts roll. Not saying that that's going to happen here. But that's part of how we make sure that we get the returns we're expecting to get.

Our next caller is Keith Stanley with Wolfe Research.

I wanted to start on the $500 million Haynesville gathering project. When would the expansion capacity be in service? And what's the projected time line for the volume ramp to get to returns? And then relatedly, how do you think, if at all, about potential Haynesville takeaway pipelines given all the Louisiana LNG projects we're seeing and your expanded gathering presence?

Sure. So on your first question, we plan on getting all of our facilities in by the end of the fourth quarter next year. And so we do see volume ramping up along the way. Really, we're adding treating capacity and we're adding incremental pipe loops just to get -- unlock some of the hydraulics there. Look, as we think about the outlook in the Haynesville, you've got a very productive basin that's very close to the demand centers that we've been talking about. And so there's a definite need to get incremental molecules to those consuming basis -- they're consuming -- the consumers, right? We got to get the physical molecule there. So as far as the build-out, the existing build-out that's there, given the growth that we see on the Gulf Coast, I think all that does is creates incremental opportunities for us in both our interstate and intrastate networks to be able to connect the dots. You've got a lot of convergence at Gillis right now. We're exploring opportunities downstream of Gillis to connect the market to that supply that's aggregating at Gillis. And if there's an opportunity, we could even consider tying in some of that Kinder Hawk production on another takeaway project out of the basin. But once again, all of that's got to be contracted for, and it's got to make economic sense.

Great. Second one, I wanted to follow up on some of your opening comments, Kim, on the permitting improvement and the order 871 and no longer having to wait the 5-month waiting period before starting construction. When you think in aggregate about those improvements that you're seeing, could this meaningfully accelerate the time line on some of your larger projects versus original expectations?

So the answer is it depends. So this is a -- on 871, it is a -- it's 1 year, but they've got it out for notice and comment. And I think our expectation is that they likely make this permanent, but we'll just have to wait and see. And so right now, with respect to the 1-year extension, not a lot of benefit for us. But if they make it permanent, then yes, there will be benefits to our major projects. And so it's going to depend and the reason it depends is it depends on the procurement schedule. And so when we get the pipe and when we get the compression. So there are certain projects that we will be able to move up by about 5 months and take advantage of, and there are others that we won't.

The other thing I'd say is on the prior notice. That has increased by 50%. So now it's $61 million. That means you don't have to file for a 7c for projects that are less than $61 million. So the permitting process is much quicker. And so we will definitely benefit from that increase in the prior notice limit. The other thing I'd say on the bigger projects is we've actually filed for a waiver for 871. So we're not waiting on the notice and comment period to be complete. We've asked them to decide independently on our big projects, South System 4 and MSX. And I think we view the likely outcome of that favorably at this point.

Our next caller is Zack Van Everen with TPH.

Just going back to the Haynesville expansion real quick. Can you guys speak to the volume or capacity that you're adding there? And then is this mainly from your larger customers? Or are you seeing demand from some of the privates that feed your system as well?

It's both. So it's from the larger customers and it's from the private and somebody may be able to speak to the capacity. But I mean they are ramping up significantly. If you look at our supply numbers and Tom, help me with this because you talk to the Board about this today, but we are expecting -- Wood Mac is expecting a doubling in the production coming out of the Haynesville. So I mean it's increasing by, I don't know, from 13 to 26 -- 26 by 2034. So I mean, that gives you a sense of the type of volumes that we are talking about.

Got you. That makes sense. And then maybe one on the LNG side. I know Tennessee Gas feeds the Plaquemines facility and VG continues to talk about potential further expansion at that site. If they were to do that, does Tennessee Gas have the ability to expand more to feed LNG in that area?

So first, if they were to do that, I think it further creates opportunities for us with these projects that we're bringing across. I think ultimately, it could -- Tennessee is already full in multiple directions, but we've got the bottleneck -- debottlenecking capability as we bring this incremental supply from West to East that I've been talking about on the last few calls. We talk about Texas Access project, which is kind of continuing on the theme.

We talked about Trident and we talked about the header and now we're actually extending into Texas to take volumes across to Louisiana. That helps debottleneck. And so if Plaquemines were to further expand, we would look at opportunities to bring incremental gas to the basin to that area from not only but some other -- from some of our other pipes in the area, including potentially looking at accessing the Haynesville in a different direction, right? And so when we talk about Gillis and kind of the directions that these pipes may head, one of those may be going that further eastward direction to kind of help fill that incremental need.

Our next caller is Jason Gabelman with TD Cowen.

The first one I wanted to ask was on the Bakken, given the Outrigger deal has been closed for quite some time. I think you are at least 6 months and H is close to ramping up here on the conversion. So just wondering what the strategy is on gaining volumes there and kind of securing potentially higher rates that, that region has to offer versus other basins?

I'll take that. So one, the integration, as we talked about has gone well. We're looking at incremental network and bottlenecks to be able to gain further efficiencies out in the basin. But as far as it goes -- as far as Highland Express goes, we just continue to work with our customers there. I don't have anything to report on that. We're making progress, but nothing for this call.

Okay. And then just maybe longer-term question. You've talked a lot about the LNG growth on the U.S. Gulf Coast and the boom it's been for your business. There is some concern that after this wave of capacity, there's going to be a potential oversupply in the market. And I wonder if you're -- in your conversations with LNG customers, hearing anything around a potential slowdown in contracting or need for additional piping into future plants after this wave of capacity comes online or if your LNG customers really expect new builds to continue at pace through the decade and into the 2030s?

I mean, from my perspective, I mean, we're not seeing -- and you can see this from what the LNG builders are announcing, which is they continue to announce new projects. and sign new contracts. And we see -- we continue to see projects get announced and projects get expanded. And I think part of the reason that you see that is it is a favorable environment right now to get projects built in the U.S., number one.

Number two, I think that from a trade negotiation standpoint, it helps on the balance of payments and the whole tariff discussion to take gas from the U.S. So I mean, to date, we have not seen any slowdown in our discussions with these customers.

And Tom, you might share your model that you showed the Board today in terms of overall growth in worldwide demand and the U.S. portion of it.

Sure. I mean, as Richard alluded to in his comments, world demand is expected to grow by 25% between now and 2050. And much of that growth, actually more than 25% will be filled in our view and I think in the view from others in the market with LNG. Most of that growth, as Rich said, is in Asia, basically areas where they don't have production. So it's going to have to be LNG that ultimately fills that hole. And what we've seen so far is that the U.S., while the overall demand profile is growing, the U.S. market share is growing as well.

So it's almost a doubling effect of the benefits of having LNG infrastructure growing in the U.S. And I think that's for a few reasons. One, the rule of law here in the U.S. as compared to other places around the world. There's a very advanced network within the U.S. such that if there's ever a need to leave molecules back in the U.S. and optimize those from a world price environment versus a domestic U.S. environment, we have a great network of infrastructure here in the U.S. to support that. And then I think the track record. I mean, I think the developers in the U.S. have done an extremely good job of being successful in getting projects online timely and providing competitive rates. And we have a tremendous supply resource here in the U.S. that I think gives customers internationally a lot of comfort in knowing that there's going to be a plenty of molecules behind these 20-year contracts that they signed with U.S. developers and with customer -- midstream companies like us. So I think the U.S. is in a great place. to continue to grow well north of what the overall global gas demand growth is between now and 2050. So I think that means more to come beyond what we see in the immediate line of sight of projects.

Our next caller is Brandon Bingham with Scotiabank.

Just continuing on the LNG theme here. Could you maybe discuss some of the incremental opportunities you see maybe outside the Haynesville? And concurrently, which basin or basins do you expect to be sort of next on deck to meet all of that growth that you guys have been talking about?

Yes, sure. So outside of the Haynesville, we've talked about this before. The lean Eagle Ford is going to be important. One of the key themes that's kind of coming to surface is low nitrogen, the nitrogen quality of the gas. And as you think about LNG plant efficiencies, lower nitrogen equates to better production. So we think the Lean Eagle Ford is going to come into play, especially as it pertains to some of the Texas LNG facilities. You've obviously got the Permian.

When we think about the Utica and the Marcellus, given the constrained nature of the basin, it's going to be hard to get extra capacity out there. That being said, we are evaluating some opportunities to move incremental gas out of the Utica down south using our Tennessee network. And so that's in its early phases. It's going to take an all of the above approach because it's not just the LNG folks that are looking for molecules. It's the power demand that we just talked about, and it's also the existing organic LDC and the basic power that we've been talking about since January of 2024. All of that is going to be growing and needing access to molecules. So it's an all-of-the-above basin approach. We've even talked about our Bakken egress project on the residue side, moving gas out west. I mean that's another example of something that's going to come into play as this demand kind of matures.

Okay. Great. And then maybe just on the full year budget commentary regarding the EBITDA, reiterating the commentary there about exceeding by at least the Outrigger contribution. Could you discuss some of the areas you see outperforming expectations in 2H that sort of offset some of the lighter performance we've seen through 1H to kind of meet that expectation?

The outperformance in the second half of the year, consistent with what we've seen in the first half of the year, really. Natural gas capacity sales, the Outrigger acquisition contributions parking loan services on our natural gas business, the Jones Act tanker contributions, those are all some of the items that are contributing to the second half outperformance, and those are consistent with what we've seen in the first half. I would say there was a little bit of timing between the first quarter and the second quarter. We didn't see some of that show up in the first quarter, but out river particularly in some of the pals performance as well.

Harry Mateer with Barclays, you may go ahead, sir.

David, earlier, you made the point that most of the expected reconciliation bill benefits come from the treatment on depreciation, which I think makes sense is it doesn't look like the 30% of EBIT deductibility for interest was a material constraint for KMI. But having said that, does the expanded interest deductibility cause you to rethink anything on the financing or balance sheet side moving forward to take greater advantage of those tax benefits on interest expense down the road?

No, it really -- it's a good question, but no, it really doesn't. I think our financing strategy is pretty straightforward and simple. It's pretty plain vanilla. And we don't have a ton of external capital needs to fund our growth projects. We can fund $2.5 billion internally from cash flow that we generate as that EBITDA continues to grow, that will continue to grow. And so we really just use our external financing strategy to refinance our maturing bonds and this tax reform won't influence that in our view.

At this time, I am showing no further questions. I'll turn the call back over to you for any closing comments. Thank you.

Thank you very much. Have a good evening. .

Thank you. This concludes today's conference call. You may go ahead and disconnect at this time.