Kinder Morgan, Inc. (KMI) Earnings Call Transcript & Summary

Okay. If we could go ahead and be seated, we'll kick this off. I'm Rich Kinder, Co-Founder and Executive Chairman at Kinder Morgan. I want to welcome you all to this investor conference on this beautiful day in Houston, Texas. As always, of course, we'll be making statements this morning within the meaning of the SEC rules. So when we -- when you listen to our projections on a going-forward basis, be sure and consult our SEC filings to make sure that you understand the risk and any projections that any company makes to you. What we're going to try to do today is to give you a detailed look at the expectations that we have for 2024. And I think equally important to give you our view of the long-term outlook for Kinder Morgan and the industry-wide trends that support that long-term output. Now if you start with this first slide, looking at Kinder Morgan itself. First of all, we're a leader in U.S. energy infrastructure. Warren Buffett talks about economic moats, and that's a guiding principle of his and Charlie Munger's the Late Charlie Munger's investment strategy. And I would argue with you that Kinder Morgan, like a lot of other midstream companies has a pretty big economic moat around its irreplaceable assets, its pipeline and terminal network. And I would argue that it has gotten even -- that moat has gotten even deeper and broader as a result of the Herculean problems that any entrant into this area has in building new infrastructure, particularly outside of Texas and Louisiana. So I think in that sense, midstream infrastructure and particularly Kinder Morgan has a real notch in its favor in that regard. Now we have growing natural gas-focused cash flows. I think there -- and we'll talk about a lot of this morning, there's a robust macro environment that gives us opportunities to not only improve that cash flow, but also to expand capital in a conservative way to add to our cash flow and therefore, increase the ability to distribute cash to our shareholders and our debt holders. We pride ourselves on being by shareholders for shareholders. And I can tell you that as the largest shareholder, that's certainly we -- certainly something we stress every day at Kinder Morgan. And I've always, in my personal investments, I wanted to be alongside people who had skin in the game. And I think that's just what we have at Kinder Morgan. Looking at the next slide. This is a slide that is interesting to me. I hadn't seen this information presented in exactly this way. And let me take just a minute to explain it to you. What this is, is trying to grasp -- based on S&P 500 criteria, trying to grasp who really generates substantial free cash flow for its debt holders and its shareholders. And if you see all the way to the upper right, you can see that midstream companies and Kinder Morgan fits right within that, have been by far the best producers of cash flow. Now how is this chart manufactured? If you take Kinder Morgan, for example, over this period of time, which is 2019 through 2023, over that period of time, we paid out $12 billion in dividends, and we bought back $800 million worth of shares. So we've generated $12.8 billion that we distributed out to our shareholders. If you take that as the numerator and our market cap pitifully low as it is, in my opinion, if you take our market cap as a denominator, that gets you to roughly a 32% return from Kinder Morgan, and that's pretty consistent with the midstream business. Why is that the case? Well, I think it shows, first of all, that midstream's long-term fee-based contracts really survive and prosper no matter the commodity price, no matter the ups and downs of the market. And I think that in a broader sense, it shows that dividends and share repurchases, if you're looking at that as an indicator of the health of a company that, that is really present in the midstream area and particularly at Kinder Morgan. Now let's look at the cash flow that we've generated and returned to shareholders. This slide goes all the way back to 2016 through 2023. If you look at Kinder Morgan specifically, we've generated a great deal of cash flow, and we've returned about 2/3 of that, 64%, to our shareholders and debt holders. Now let me give the economics behind that. In this period of time, from 2016 through the end of last year, we paid out $16.3 billion in dividends. We paid -- we did $1.5 billion in share buybacks. So we have a total of right at a little over $18 billion. Again, put that over the total cash flow generated and you come up with 64% of what we've done with the $8 billion of debt and $18 billion of equity returns, $26 billion. Again, that's the numerator. Denominator is the $41 billion of total cash flow. So we've routed through to our shareholders and debt holders 64% of all that free cash flow that we have generated. So when you think about and look about, well, what have you done for me lately? We don't like this. We don't like that. Well, look at this and I think the message from this slide is that we've increased the dividend. This is the seventh consecutive year we've increased it going from $0.50 to $1.13, and we've maintained strong dividend coverage. We've decreased our leverage by 1.1x. And we ended 2023 at 4.2x debt-to-EBITDA. Really, it's better than that. We had the big acquisition that closed 2 days before the end of the year. If you take into account the expected EBITDA from that acquisition, you actually get down to 4.1x. And as we said, we expect to end this year at 3.9x. So we've decreased our leverage. We've made it a very solid balance sheet, we believe. And then as I said, we've also had opportunistic share repurchases over the years. And we still have excess capacity under what our Board has authorized us to do in the future. Now what's underpinning this optimism in terms of the longer-term outlook for Kinder Morgan and again, other midstream companies, we have a bullish outlook on U.S. natural gas demand. We expect it to grow about 20% by 2030. Now let's look at the numbers here again. In 2023, we believe we ended up just over 108 Bcf a day of demand. We expect that by 2030 to be over 128, almost 129 Bcf, or an increase of about 20 Bcf a day. Now how accurate is that projection? It's pretty well accepted, I think, by Platts, by S&P, about everybody who is opining in the field. Let's look at what's driving that growth. 16 Bcf a day is coming from LNG export facilities. How real is that? Well, of that 16 Bcf a day, about 11 Bcf a day is already under construction. If you happen to read the Gas Daily this morning and talking about '24 and '25 specifically, they're projecting, and we agree with this, that because Golden Pass got pushed back into '25, they add in '24, will probably only be about 1 Bcf, a little over, 1 Bcf a day. But in '25, now that Golden Pass has shifted to that year, they're predicting about 7.5 Bcf a day capacity add in 2025. So over the next '24 and '25, over the next 20 months or so, they're projecting add of 8.5 Bcf a day or over half of the total 16 Bcf a day that we and others are projecting will be added from LNG export facilities by 2030. Another thing you can hang your hat on is that about 11 Bcf a day of that 16 Bcf a day is already FID-ed and under construction. So we feel very good, and I think the general market does and the general natural gas industry does that over these next 7 years or so, you're going to have dramatically increased the amount of natural gas consumed in our LNG facilities. Now we also expect exports to Mexico to grow about 3 Bcf a day. We expect increased industrial demand. And again, almost all of this in all these categories, is relevant to Texas and Louisiana, which, of course, is the best place to build infrastructure today and we think the best place to operate. So that gets you 20 -- 22 Bcf. If you look again at Platts, they're forecasting rounding that down to 20 because of about 2 Bcf a day or so loss of heating demand. At Kinder Morgan, we don't necessarily subscribe to that. So I would say the 20 Bcf a day may be a little light on the actual forecast. But any way you cut it, we're talking about a substantial increase. I'm old enough to remember when I started out in this business, the total U.S. demand was about 32 Bcf a day. So this is how far this industry has come. And we see no chance of it not continuing to grow over the foreseeable future. Now I think every company will stand up here and say that we ought to be a part of your core holding. I think that's pretty well pro forma for anybody presenting. And we obviously feel that way, too. But if you look at it, why would you invest in Kinder Morgan? Well, first of all, if you come back to this natural gas story, we move about 40% of all the U.S. natural gas production. We have a management team that's aligned with equity interest. We have a nice increase projected in this budget this year of about an 8% increase in EBITDA, better than that on EPS. We have a 6.5% current dividend yield, among the highest in the S&P 500. And as I said earlier, we still have capacity to buy back shares if and when we want to do it on an opportunistic basis. So I think the real takeaways we hope you have this morning in terms of a long-term outlook for Kinder Morgan is this. Number one, the natural gas story has real legs. We don't think there's any question about that. We think at Kinder Morgan, we're positioned to take advantage of that story. And third, we think this will lead to increased cash flow by -- for two reasons, number one, there will be increased utilization of our present assets. And secondly, there will be enormous opportunities to expand our system, again, primarily in Texas-Louisiana. All of that will lead to more cash flow generated and more ability to distribute that cash to make good investments with some of that cash and distribute the rest to our shareholders and debt holders. So that's why we're optimistic on the future. And I hope that after today, you'll conclude what we say makes at least a degree of sense. And with that, I'll turn it over to Kim.

Okay. Thanks, Rich. So today, we're going to start with the assets. And so as Rich said, we've got an irreplaceable portfolio of energy infrastructure assets. If you look at our business, about 64% of our business is in natural gas. We have the largest natural gas transmission network in the United States. We move about 40% of all the U.S. natural gas production. We deliver 45% of the LNG export feed gas. And with the South Texas acquisition, we expect to deliver around 50% of the exports to Mexico. And we have about 15% of the U.S. gas storage capacity. 26% of our business is really in refined products. So we're the largest independent transporter of petroleum products, and we're the largest independent terminal operator in the United States. We move 1.7 million barrels a day of refined products, and we've got 135 million barrels of liquid storage capacity. And we've got 16 Jones Act tankers. Our CO2 and our ETV segment are about 10% of our overall business. We're one of the largest transporters of CO2. We produce CO2 in Southwest Colorado. We transport it through our pipes down to the Permian Basin, where we inject it to produce oil through enhanced oil recovery. We also have one project underway to transport and inject CO2 -- capture CO2, and we're working with customers on additional volumes. And we have a growing RNG in our ETV business. By the time we get all our projects in service by midyear, we expect to have over 6 Bcf of RNG production capacity. The bottom line on this page is that our portfolio of assets cannot be replicated or replaced. And as Rich said, that's because over time, population has grown up. It's more difficult to build. It's also more difficult to get things permitted. There's more opposition. And so this portfolio of assets, as Rich said, has a nice moat around it. Now we use that portfolio of assets to help drive shareholder value. And so we drive shareholder value through our focus on natural gas. I already mentioned 64% of our cash flows come from natural gas. And that's a growing market. We've got a strong balance sheet. So we're BBB rated, investment grade. We've ended the last 3 years in and around 4x debt-to-adjusted EBITDA. We expect to end 2024 at 3.9x debt-to-adjusted EBITDA. We've got a nice backlog of high-returning growth projects. So we've got $3 billion of committed projects. We expect to bring those on at less than 5x EBITDA build multiple and that will add nice future growth for Kinder Morgan. We also have very predictable and growing cash flow. 68% of our cash flow is take-or-pay or hedged. And then if you look at the growth from '23 to '24, we expect to grow adjusted EPS by about 14%, and we expect to grow adjusted EBITDA by about 8%. And we turn -- we returned a lot of money to shareholders. In 2023, we returned about 8% per share to our shareholders through the dividend and opportunistic share repurchase. Now we've discussed that these assets are hard to replicate. The question is -- that a lot of people have is, well, what's the future need for them? Because there's a lot of studies out there that show -- that predict extreme decline in the products we move and then we store. And so if you look on the right-hand side of your screen, you'll see the 2023 IEA projection about what happens to natural gas and crude. And so they're predicting a precipitous decline in U.S. energy supply of natural gas and crude. And they're predicting that, that gets replaced by renewables such that by 2050, natural gas and crude production is dropped off almost completely and that renewables are providing most of the market. Now we have seen extreme forecast before. And so we share a couple of them up here with you. In 1956, Shell predicted that we would reach peak oil in the United States in 1970. And that, that peak oil would occur less than 3 billion barrels per year. And that by 2024, you can see we're down there close to zero. So really, the oil production in the U.S. is inconsequential. Today, if you look at the current rate that we're producing, we're producing about 4.8 billion barrels per year. So we're all the way at the top of the graph, almost off the chart. Another study was 2006. The association to study of peak oil predicted that, this is global, global oil and gas production would peak in 2010. Obviously, that didn't happen. We're above those 2010 peak levels today. So we would submit to you that like many of the extreme forecast before, the IEA will not be accurate. So -- and the reason is on the next slide which -- and there are two of them, energy transitions take a long time and what has happened in the energy transitions is that it consists of adding new forms of energy, not eliminating the old forms. So in terms of it taking a long time, you can see coal took 60 years to achieve 50% market share. Oil took 60 years to achieve 40%. And natural gas took 60 years to achieve 20%. Now if you look at the right-hand side of the page, you can see that oil has lost market share over time and coal has lost market share. But what's more interesting to me is the amount of these products that we use has continued to increase. So the only one that hasn't increased is biomass and it's actually stayed relatively flat. So we think a more accurate prediction on the next page is the EIA forecast, which is consistent with the ideas that energy transitions take a long time and that we're going to need more of all energy sources. We also believe that the current energy transition will have the same characteristics. Why do we believe this? Well, because the fuels that we use today are available, they're cheap and they're reliable. And there is no alternative that can say the same. Energy is a $5 trillion plus industry, and it's very complex. And the fuels that we move and store today, there's huge infrastructure built-in infrastructure associated with that. And so when you have big, complex industries with huge and solid infrastructure, they just take a long time to change. There's huge capital costs associated with the transition. And we expect energy demand like it has in the past, will continue to increase as the standards of living improve in places like China and India and Africa. And we've started to see some practical evidence of this in the market. Texas has announced, we're adding natural gas peaking capacity here. California has extended the life of Aliso Canyon. It's extended the life of some of their natural gas power plants. You've seen canceled wind projects in the Northeast as the costs have soared. So we believe our assets and services are going to be needed for a long time to come. So turning to natural gas demand in the U.S. If you look at the last 8 years, we -- natural gas demand has grown by 30 Bcf. And as Rich mentioned, over the next 7 years, we expect that to grow by 20 Bcf a day and potentially more. So the future for U.S. natural gas is very bright. And that has positive implications both for our existing business and for our ability to expand. So let's start with what that means for our existing portfolio of assets. So the 39% growth in U.S. natural gas since 2015 has led to increased pipeline utilization. So you can see our five largest pipes, you can see that average utilization has gone from 73% to 87%. This is average. And so if you think about peak when you have cold weather or you've got hot weather, obviously, those utilizations are higher than that. But on average, we're at 87% right now. And what that means there's more scarce supply of pipeline capacity and therefore, it is more valuable. And what is happening is that's leading to increased contract terms and/or increase rates on our pipes. And so a couple of examples we've provided you here on the Texas Intrastates, the average contract term has gone from 5.3 years to 6.7 years. On EPNG, the average contract term has gone from 5.8 to 7.1. And then in addition, this higher utilization, this increased demand is driving new projects. And so, of our $3 billion backlog, about $2.2 billion of that is associated with natural gas. We expect to continue to see growth opportunities in natural gas. So on the next slide, the biggest driver of the natural gas growth, as Rich mentioned, is the 16 Bcf a day growth in LNG exports. That is more than a doubling of U.S. LNG exports. And that is mainly occurring along the Texas and Louisiana Coast. KMI currently has in place contracts to supply about 10 Bcf of that. We're pursuing contracts for up to another 13 Bcf a day. And it's not just about the direct connection to the plants. People think, oh, well, you build an LNG export terminal. You connect it to the nearest liquid supply point and you're done. I mean that's not what's happening out there. What is happening is -- yes, that's the initial step with these plants. But then they start looking around and say, I'd like to get cheaper supply than I can get right here at this closest point. And what happens if you get -- something happens -- an upset in a basin, I need to have more diverse supply. So then they start looking at expansions back upstream to get more diverse supply and more competitively priced supply. So one LNG project can lead to multiple projects across our portfolio of assets. Another impact of the Gulf Coast LNG exports is that it is leaving the South East short of supply. And so the Southeast is short supply, and we're working on a couple of projects, not yet brought to fruition, but a couple of projects to bring more supply into the Southeast market to provide them the natural gas that they need. Now on the next slide, another driver of natural gas demand growth is the need to back up renewables. Now I think what is very much underappreciated is that as you increase renewable share of the power stack, you actually need more natural gas pipeline capacity and more storage. And so this slide illustrates that point based on what we've actually seeing happen in ERCOT. So if you look at first two towers, 2010 and 2023, you can see in 2010 that -- between 2010 and 2023, that power demand grew by about 40%. That's from the top of the green to the top of the green. In addition, what you see is the peak, which is in the dotted lines, increased from 339 gigawatts per hour to 496 gigawatts per hour. And during that time, you can see the renewable share went from 9% to 32%. So in an extreme example, when wind doesn't blow, the sun doesn't shine and you're in a peak demand period, for example, in 2010, natural gas would need to increase to supply the power plants with 80 plus the 339 gigawatts per hour. So it would need to increase to supply 419 gigawatts per hour. Now if you look at that same case in 2023, it would need to cover the 391 gigawatts per hour plus the 496. So 887 gigawatts per hour. So the need for natural gas actually more than doubles between 2010 and 2023 in this extreme example. Now we're not going to -- we're probably not going to back up 100% of our renewables but that doesn't change the underlying point that as renewables become a greater share of the generation mix and as electric demand grows, natural gas -- the gas supply will need to increase much more than it has in the past. And with existing pipelines highly utilized, that's going to require additional pipeline capacity and storage capacity. So that's what we've seen happen in the past. On the next slide, we look at what McKinsey projects to happen in the future. So the towers on this page don't represent the entire power -- entire generation stack. They're just showing the natural piece of the generation stack. So you can see in ERCOT, on the left-hand side, McKinsey is showing that peaking capacity between 2021 and 2040 will need to increase from 1.5 terawatts per hour to 2.4 terawatts per hour, a 60% increase. So more of the same. If you look at MISO, the situation's even more significant, increasing by 80 -- 86% versus what's needed today. And so today's pipeline system is generally not sized to cover the projected increases in this peak demand. Another driver of natural gas is the conversion of coal-fired generation to natural gas. There are about 45 coal plants that are slated for retirement that are within 50 miles of our pipeline systems. So even if you didn't convert that to natural gas, even if some of that was converted to renewables, you're still going to need to back up a part of that. And so we expect that the conversion of natural gas of coal plants will continue to drive increased demand in natural gas. All right. Switching gears now from gas to refined products and refined product demand. There's been lots of noise in the market about the internal combustion engine being replaced with the electric vehicle and the resulting impact on product demand. And so in the first quarter last year, we started looking at putting together our own forecast about what we expected to happen with refined product demand. And we've since updated that, and we're sharing that with you here today. We looked at lots of different forecasts as we look to put ours together. And ultimately, we decided that with respect to diesel and jet fuel, that the EIA's numbers were just as good as anyone that -- any numbers that we could come up with. EIA projects that diesel demand declines a little bit over this period as engines become more efficient. It shows jet fuel increasing a little bit over this time as they link jet fuel with personal consumption that grows over this time period. But on gasoline, we didn't believe that the EIA's EV penetration was sufficient. We didn't think it was aggressive enough, so we came up with our own forecast. So our forecast assumes that EVs as a percentage of new car sales increase every year from today, and they reach 47% of new car sales by 2040. And that as a result of that, EVs comprise about 23% of the U.S. fleet in 2040. So horseshoes and hand grenades, I just sum it up, it's 50% of new car sales in 2040, and it's about 1/4 of the market. And the resulting impact of that on U.S. refined products demand is approximately a 1% decline per year on average between now and 2040. Now our pipelines tariffs have inflation escalators. A lot of our terminals contracts have inflation escalators. There are also regulatory adjustments that can be made on our pipelines when things change. And we have some nonjurisdictional revenue growth. All -- with all those levers to pull, we expect to largely be able to offset this volume impact. And so this business is going to continue to generate lots of cash for us for many, many years to come. Now we also have an area of growth in our refined products business, and that is on the -- that's on the growth in biofuels. So increased biofuel demand has provided us a number of attractive opportunities for investment at our existing facilities over the last few years, specifically on renewable diesel. We've been able to expand our renewable diesel capacity at existing facilities on the West Coast. We have built some -- we've added to our existing terminals to be able to handle some renewable diesel feedstock down in the Lower Mississippi River. And so you can see on the right-hand side of the page that these projects just -- plus moving these increased volumes through our existing terminals, the biodiesel volumes have increased by 8% between '22 and '23. Renewable diesel volumes have increased by 150% and renewable feedstock volumes have increased by 11%. And that growth is expected to continue, as you can see on the left-hand side of the page with renewable diesel expected to increase by 45% and biodiesel by 53%. And then potential newer product coming into the market is SAF, sustainable aviation fuel. And we're talking to customers on a couple of projects in the Gulf Coast about potentially handling SAF for them. So now switching to our ETV business. Here, there's a growing demand for renewable natural gas. Renewable natural gas is biogas that's generated from landfills. It's generated from livestock operations. It's generated from wastewater treatment plants. And then it's cleaned up to a purity standards such that it can be burned in power plants or transported in pipelines. And so our focus has been on the landfill aspect of renewable natural gas. We've made about $800 million of acquisitions in this space over the last couple of years. We'll spend another $300 million on expansions. And so we'll have a little over $1 billion invested in the space by about midyear this year. And we expect that, that investment will earn us less than 6x multiple. So this is a market. You can see that Wood Mackenzie expects to continue to grow. They're showing about 11x increase in this market. And we expect that landfills as opposed to some of the other RNG potential opportunities will drive this growth given their larger scale, they're generally lower capital costs, they're generally lower operating costs. And so we expect to find opportunities to continue to participate in the growing demand for renewable natural gas. Now also in our ETV business unit, we are focused on carbon capture. As I said, we're working on our first project, and we have another -- we have a number of other potential opportunities that we're working on. The U.S. carbon capture market is projected to increase tremendously by 2050, and we are very well positioned to participate in that. We know how to build and operate CO2 pipelines. Generally, CO2 needs to be transported in specially built pipe -- special purpose pipes in order to really do it efficiently. You can transport CO2 through repurpose pipe, but generally, it's not efficient to do so over any meaningful distance. So also from our years of experience in EOR, we know how to inject CO2 in the ground. We know how to track where that CO2 goes. We know how to keep it in a certain pore space. And that's going to be very important for people who are getting that tax credit, generally, the capture of the CO2 is getting the tax credit, because you have to be able to prove that it's staying within a certain pore space. And so in our fields in West Texas, we've installed, for example, water curtains to be able to keep those CO2 molecules in the certain pore space. So we know -- we have that expertise in injecting CO2 and keeping it in the ground. And so we expect that we will be able to participate in this rapidly growing market in a more meaningful way than we have today. Now shifting from how we grow our business to how we operate it. Our focus is on doing business the right way every day. And so we're committed to being a good steward of the environment, of the assets that we own, of the people that we employ. We have been focused on reducing methane emissions since the inception of this company. We have been involved in the EPA Natural Gas STAR Program and the EPA Methane Challenge program. And if you look at our methane emissions since 2020, we've reduced those methane emissions by 31%. Part of that reduction has come from leak detection. And so at this point, we are serving 100% of our natural gas compressor stations annually for leaks. And then over time, we expect to move those surveys to quarterly. We've been focused on safety -- we've been -- for the entirety of this company's history. Since 2007, we have been publishing safety statistics by business unit on our website. And then starting in 2017, we began rolling those safety metrics up into a single metric for the whole company. And so if you look at our TRIR, that's our total recordable injury rate since 2017, we have reduced that by 20%. That's really important because when your employees come to work, they need to know that they're going to be safe, that they're coming to a safe place to work. It makes it easier for us to hire people when they know that they're coming from -- to a safe place to work, and it makes employees more likely to stay. And so this is very important for us, and that's why we focus on that. We've seen continued improvement in our environmental, social and governance score. Since 2017, we've improved from a B at MSCI to AA. We do diversity and inclusion the right way. We're focused on hiring the most qualified candidate but we always try to include a diverse candidate in our pools. We also use panels when we're hiring. And that's so that if I'm hiring someone, I have the tendency maybe to hire someone who looks like me and who thinks like me. But if there's a diverse panel, you're more likely to get diversity of opinions and therefore, likely not to get bias in the decisions. And so we have increased female employee representation in management by 22% since 2018. And then if you look at our backlog of projects, over 80% of our projects are focused on investing in low-carbon fuels. So I'm going to wrap this up where we started, on how we shareholder value. We have a focus on natural gas. As we talked about, it's 64% of our portfolio, and it is a growing market. We have a strong balance sheet. We expect to end 2024 at 3.9x debt-to-adjusted EBITDA. We've got a nice backlog of high returning projects, $3 billion expected to bring on; a build multiple at less than 5x. We've got predictable and growing cash flows, 68% of our cash flow is take-or-pay or hedged. We've got growth between '23 and '24, really nice growth for a midstream company. 14% in adjusted EPS, 8% in EBITDA. And we're focused on returning substantial shareholder -- substantial value to shareholders. In 2023, we returned 8% per share through the dividend and opportunistic share repurchase. So with that, Sital and I are going to do a fireside chat, and I will pose a number of questions to Sital, which he will provide some answers. I think it will be very interesting. We felt like that, that would be a more interesting way to do this than to have him just come up and talk to you like I just did. All right. So for those of you who don't know Sital, Sital became President of the Natural Gas Pipeline Group in January of last year. So he's been in the job for about and he replaced Tom Martin, who will present next, who is now President of Kinder Morgan. Sital has been -- before becoming President of Natural Gas he was President of the Midstream division of natural gas. And before that, he was on the TGP commercial team. So he has experience both on the unregulated side of our business, and on the regulated side of our business. And so he's got some great -- to share with us today. So if you all flip to the first slide. And so Sital, why don't you talk to us a little bit about the growth from the various supply areas and the potential opportunities for KMI.

Absolutely. And for those of you that don't know how to say my name, it's pronounced like lethal, put in an S in front of it. Lethal, Sital. So pleasure to meet you all. Looking forward to this conversation. As Rich and Kim alluded to, there's -- the outlook for natural gas is tremendous, right. And so we're focusing on supply here. And we've got a lot of projects in queue. I think the key takeaway on the supply side is, there's plenty of it. The U.S. has plenty of supply. It's really there to respond to the demand that we see coming. And so this is a WoodMac view, by the way, and I'll probably -- along the way, we'll highlight some differences. But the overall supply is projected to grow by 19 Bcf over a period through 2030. That's primarily reacting to the demand that we're going to talk about. When you think about where all that supply is coming from, you've got the Haynesville, as a primary source plus 9 Bcf a day. And -- what I'm going to do is I'm just going to talk to you about what I'm doing in each of these respective basins because the opportunity sits there, the teams are working very hard to capture these opportunities. And so I'll start with the Haynesville. Obviously, we have our KinderHawk gathering system there. We have been working feverishly to expand the system. The team has done a good job. We have -- we are at capacity on our KinderHawk system. We continue to further invest in the asset. Even this -- in 2024, we have producers effectively waiting on incremental capacity on the system. We're also looking at a lot of the upstream projects out of the Haynesville, or aggregating supplies to the Giles area. We -- with our network, we're looking at ways to expand downstream of Giles. What is there to do? How do you get that last mile connectivity into the LNG consuming areas, right, I mean there's a lot of LNG demand that we're going to talk about. Well, infact that gas is aggregating at Giles, how do you get it and as Kim alluded to, the upstream to the downstream, we're looking at ways to get incremental projects out to the last mile. Permian, it's its own story, right. It's associated gas play. We see roughly 7 Bcf of WoodMac 7 Bcf of incremental associated gas growth there. Clearly, here, the focus -- when you think about from a production side is all around egress, right, I think there's a market element to it that we'll talk about. But when you're focusing on production, we're looking at not only the greenfield opportunities. We've got several brownfield opportunities that we're looking at. For example, there's a small project going out west from the Perm. We've got a little expansion going out west to NGPL, has an expansion going north. We call it our Perm North project. Small projects, but still brownfield in nature. We're looking at another one on NGPL. And so I think we have smaller projects as we continue to try and move gas from the Perm either West East, South to Mexico depending on where the market needs. And then ultimately, there's absolutely a need for another pipe, right, I think we talked about that on the last call? I think the general sense is the timing might be sooner than we originally thought, right, late in '26, early '27. So we're in discussions, obviously, on the greenfield piece of that. It's highly competitive. So I'm not going to get into the specifics. There's also probably another pipe needed, maybe a couple of years later. And I think the decision here is where is the first pipe going to point, right? The first pipe might point to South Texas. And then another pipe needs to point to the Louisiana Gulf Coast corridor, right. And so those are definitely opportunities that we're working on. Obviously, highly competitive. So I'll just stop there. In the Northeast, we just pull -- put in our East 300 project, team did a great job bringing that across the line. It's much more difficult to build infrastructure. WoodMac shows 5 Bcf of incremental growth. In terms of supply, I think what our focus here is probably going to be continued on the brownfield side of things, continue to focus on small network type expansions where we can leverage our footprint to capture incremental value. I think the other element here is the volatility is going to increase as demand -- Kim pointed out to the variable nature of renewables. As we start to see further renewable penetration, that's going to increase the volatility, hence further need for our infrastructure and we'll price our ancillary services to capture that value. In the Rockies, which really encompasses what we got here is #4, which is really our Bakken, Powder/DJ and then ultimately, our Uinta Basin assets. Just kind of a recap of where things stand there in the Bakken. The team has done a great job. We actually hit record volumes at Watford. If you look over the last 3 years, we've built out our system, probably spent a little over $0.5 billion, building that out. And now we're really working with our largest customers there to continue to expand our footprint. We're evaluating incremental processing capacity in the Bakken. As you all know, we did sanction a project. When we think about the basin, it's approaching constraint, right. Effectively, Bakken producers have to push out Canadian producers before -- in order to keep their production going. So we see a need for incremental egress on the residue side. We sanctioned our Bakken Express. Phase 1 is in service. We're working on Phase 2, which likely will be in first quarter of 2026. In the -- and one thing there with the residue gas that's coming out of the Bakken, ultimately, that comes into our system here at Cheyenne which is our WIC system, generally has been underutilized. And as we start aggregating that gas, bringing it into the network here at WIC, it will also increase the demand for our services on that system. So just -- it's a good way to use some of our underutilized -- maximize some of our underutilized infrastructure, tongue twister. Our Uinta Basin asset, Altamont, another asset that's also maxed out. We're waiting on capacity, working with our customers to try and improve egress there. We've got several projects that are in queue to try and expand the footprint. I think once again, we have producers waiting on capacity. I'll save the Eagle Ford last as it relates to -- there's two aspects of the Eagle Ford that we're really focused on. One is our rich window. We access the Karnes Trough, and really, you can't really see it on the map, but just if I had to differentiate, you have the rich window and you have the lean Eagle Ford window that we just have started focusing on in terms of expansion as well as acquisition. And so on the rich side, where we are today is we are approaching process -- our max processing capacity, which has been tremendous feat by the team to be able to get us there. What we've strategically done is extended further into the Karnes Trough. We've moved further east into the La Salle County area to try and expand our connectivity there. And that's attracted tremendous volumes to the point where we suspect will be sold out on processing by the end of the year. And so our focus now as we've entered into some of these long-term deals, to be able to secure these volumes. As these contracts start falling off, the focus will be on margin improvement. On the residue side, the lean Eagle Ford side, that's been a new focus of ours. We do believe that, that basin has economics that may rival the Haynesville in some areas. And so focusing on that is also been -- is going to be a key focus of ours.

All right. Sital, so this is the WoodMac forecast. And so we have views that differ a little bit in some areas from WoodMac. And so can you talk about where we see things a little bit differently. Rich alluded to some of that when he was talking on the demand side, but on the supply side where we see things a little differently.

Yes. So one is if you go look at the Northeast, I think WoodMac shows 5 Bcf a day growth. We do -- I think our general view is it's probably a little more challenged to get incremental volumes. I think with MVP -- once MVP comes on, there'll be some incremental. But beyond that, I think it's still difficult to build infrastructure. So I think we're probably about 1.5 Bs light we're in the softer side there in terms of growth. And then probably one of the bigger areas where we differ is our view is the lean Eagle Ford's going to be a little bit bigger -- the Eagle Ford is going to be a little bit bigger in terms of supply growth than maybe as indicated here with WoodMac. Our general view, as I said just before is that -- and in fact, through our discussions with our customers, that lean Eagle Ford Basin, especially out there in Webb County is -- some of the economics there probably rivaled that of the Haynesville. And as you use that lean Eagle Ford gas to be able to satisfy the demand that we're going to talk about here shortly, we think it'll be able -- it will be positioned well to react to natural gas demand increases as prices rise.

Right. And so in the Eagle Ford, we just made the South Texas acquisition. So talk a little bit about what that acquisition brings to our portfolio of assets and our ability to compete in South Texas.

Absolutely. So one, the asset fits very well with our existing intrastate system. One of the things that we've discovered as we've integrated our other assets, such as Stagecoach, there's things that you start to uncover as you integrate that you didn't even think about when you were actually deciding to purchase the assets. So those are benefits that are going to be realized sooner as you integrate the network. For example, we're already starting to look at connectivity within the intrastate system and there may be some projects that can be enabled as a result of that incremental interconnectivity. One other advantage that we see as we start to see the stronger levels of Permian penetrating the LNG markets, that gas has a much higher nitrogen content. We do believe that the blending -- the low nitrogen content that's in the lean Eagle Ford will be of value as you start to satisfy all the incremental LNG demand. At the end of the day, the way I look at it is you've got gas coming across in significant volumes. You've got low nitrogen gas. The alternative is you put in an NRU at the facility, right, that comes with an incremental cost not only from a capital cost, but an operating cost. And then you also have the reliability issues associated with the facility. We ultimately -- we decide to price -- our blending service can be priced in a way such that we get incremental value and also remain competitive versus the alternative of putting in an NRU at a facility. So look, I think that's a big advantage. And I won't -- I can't leave without talking about Mexico, the topic. I mean, Mexico has always been a very important customer of ours. As we start to integrate the asset, NET and stand-alone form could never really offer balancing services or storage because they didn't have any. As we integrate the asset into our portfolio, we'll be able to offer incremental transport storage and balancing services to Mexico.

Okay. So now we'll flip to the next slide, and we're going to talk about demand. And so now talk about the demand growth and where we see the opportunities on the demand side of the equation.

Well, as Rich alluded to, as you alluded to, demand is robust, right? I mean plus 20 Bcf may be light in terms of overall growth. But clearly, the focus in here -- I know I'll just address it in the order that we've guided on this slide. LNG demand is going to drive significant growth, 16 Bcf, 11 Bcf coming in and -- that are already sanctioned, several that are close to being sanctioned to fill the gap on the 16 Bcf. And so I'm going to save LNG really for the last because I've got a detailed slide here on the next page. But when you think about the overall demand around LNG, what that does, not only are we trying to directly connect to LNG. But as you alluded to, there is a network benefit in having that demand on -- in an area where we have tremendous connectivity. And so there's value not only to the existing network as contracts come up for renewal, but we're also looking at projects to unlock the movement of gas across the network. I'll give you an example. Some of you have seen this. It's been filed, our Texas, Louisiana project on LNG. The Texas LNG -- Texas Louisiana project to effectively move gas from Texas to Louisiana, that's an example of moving gas from one side to the other side to be able to help get gas to the consuming areas. We have several projects that we're looking at, not only on the intrastate system, but on the regulated systems on our interstate systems to be able to move gas effectively West to East and we're working on a couple, hopefully, that we'll be able to talk about next time we're here in terms of sanctioned projects. Mexico, we just talked about that, but it's not just only in Texas, right, there's an element of demand in Mexico with Costa Azul and all the other LNG projects coming out in the West Coast. The other piece that we're not talking about is the power growth in Mexico. So we think that 3 Bcf actually may be light. We're focused on ways to get incremental molecules not only from this Texas corridor, but from the western corridor into Mexico to serve the power and the growing LNG demand that we're ultimately going to see. So the team's working on several projects there to try and expand our connectivity and capabilities going out West. I will highlight this on the power side. WoodMac shows us, is relatively flat. This is probably an area where we disagree based on not only our experience with our customers, but our view is probably that power demand is actually going to grow. And we're seeing that in our discussions. Everywhere where you see a 3 here, we're actually working on opportunities to serve not only help support the renewable penetration that's occurring. But you've got coal retirements, as Kim alluded to in her slide, that are ongoing, and we're having discussions in the Southeast, in the middle part of our system here, Ohio corridor as well as up in the Pennsylvania area, where we're talking about how to help facilitate and provide peaking services to be able to backstop some of the renewables that are actually going to be in process of coming through, but not only that, the retirements that are underway as we transition here over the next few years. And so we're working on several projects that really help support that. Also in the Rockies and also out West. The Desert Southwest is actually short capacity today. As we start seeing further renewable penetration and you're seeing increasing population growth, the demand for power is only increasing, and we're having discussions on how to effectuate and grow that.

Okay. Now on the next -- do you want to talk about LNG real quick? Or...

I will. If we can flip to the next slide. Yes. And so really, the point what I was trying to make here is when you start looking at the footprint and you look at our footprint and the location of all the proposed LNG, our focus now is on how to expand and connect our systems to be able to move molecules. Because I think the key here is once you get all this incremental demand, there's going to be a fight for actual physical molecule, right. You're going to need to get the physical molecule to the consuming area. And it's not just LNG, it's the Southeast as well that I think Kim talked to on our previous slide, there's going to be gas-on-gas competition. We got to find a way to get incremental molecules to the consuming regions. And so we're working on several projects not only to move gas from Texas into the Gulf Coast corridor, but we're looking at ways to move incremental molecules from the producing regions across to the Southeast markets as well. And so those are the things that the teams are working on. I think there's a tremendous opportunity set there. I think as folks realize the demand onslaught that's coming, securing supply is going to be key. Where is that...

And we've already started having some of those conversations with the utilities in the Southeast.

Absolutely. Ultimately, the supply is going to need to come from multiple forms. You're going to have the Haynesville. You're going to have the Permian. You're going to have the Eagle Ford. You're going to need all your basins supporting the demand growth that's coming our way.

All right. Now let's shift to storage. It's a hot topic at all the investor conferences we attend. And so just with the increase in renewables, with the increase in power demand, the increase in the peaks, storage has become more and more important, and yet we have ground storage capacity. And so talk a little bit about our storage portfolio and the opportunities that we have there.

Absolutely. So we've got 702 Bcf storage portfolio spread out across the country. I think when you think about storage, you need to think about it in two ways. One, high deliverability, high-cycle storage, there's an element there. There's an element of storage that's based there for supporting our LDC customers, probably lower turn service. But when you look at our network here, one thing I think is important to take note is we've got storage concentrated in the Gulf Coast, which is really effectively market-based storage on our Texas Intrastate systems. That storage is -- that storage can be customized for our customer. As an example -- for example, LNG customers need injection capabilities. Historically, we've been focused on deliverability. And so what we're doing right now is trying to figure out how to price our service such that we can satisfy the LNG customer, satisfy the traditional LDC customer and ensure that we improve the value realized for our existing asset there. One thing to note is some of our storage, probably if you think about what portion of our storage is market-based rates, we've got about 25% of our storage is a market based rates. The other -- the balance being cost of service, so regulated by FERC tariff. Most of that is concentrated up -- Stagecoach has market-based rates. But our NGPL storage, which is a 288 Bcf of storage is mostly cost base. And our Tennessee storage sits outside; or Bear Creek storage asset, that's also cost base. And so when you think about where you can price your services, it's not going to be -- our regulated storage services are going to be governed by our tariff, right? And so when you think about value, the value in terms of [ where are you ] incremental value, the focus will be on our market-based storage assets and really focusing on the services. That being said, there's incremental value to be captured through the ancillary services that we can provide using our cost of service storage.

And so talk about that and expand on that a little bit because we create synthetic storage capacity with -- using our pipelines that I don't think people really fully appreciate, not some of the ancillary services you're talking about. So explain how we do that and then the value that's created there.

Yes. So storage in a standalone form is just that, it's storage, right? When you couple that with pipe, I think pipe and storage together can allow a certain amount of flexibility using the pipe line pack as well as the variability in our ability to move molecules using that pipe. I think ultimately, there, you get incremental opportunities to provide physical service to our customers. And I think that's a distinguishing factor as an operator. If you own the physical asset, not just the storage field, but the pipe that goes with it, I think it enhances our ability to provide variable service.

And so we provide, like on our Texas Intrastates, no notice service, right?

That's right.

And we do things on our interstate system like park and loan business, or imbalance services and power serve, which the combination of the pipeline in the storage facility allows us to offer some of these incremental services. So it's not just the revenue that we're earning from the pure storage facility. It's also the revenue that we're getting on the pipeline.

That's right. And power service is a good example. We recently just put that in. That's in response to the demand for our power customers that want the ability to take gas without notice, right? And...

For the peaks.

For the peaks. And so that's an example of combining storage and physical pipeline capacity to be able to provide that service.

All right. Well, I think at this point, we're pretty much out of time. And so...

I'm cut off is what you're saying.

So we have -- okay. So the last slide then it just spotlights how 95% of the growth on the Texas Louisiana, 95% of the growth in the natural gas market is occurring within Texas and Louisiana. And so to sort of sum it all up, just you can talk about the advantages that we have because of the footprint we have in this area.

So first of all, it's much easier to build infrastructure in this area. That's a plus. But if you talk about our advantage, we have not only on our Texas Intrastate systems, but our interstate systems, we have the last mile connectivity, right, to the consuming region, right. That's basically what we have that's an advantage. I'll give you an example. In Texas, you can talk about building a pipe from point A to point B. But until you access the industrial market, right, that last mile industrial market, that's an advantage in terms of something that we have. And so our assets are positioned well. We have tremendous assets that can be connected, and we're looking at ways to try and connect, create incremental flexibility there to provide service. And so our differentiator there is optionality. We provide options to our customers. We provide variable supply access across the network to our customers that we feel ultimately, in conjunction with the storage and the network benefits that we just talked about are a differentiator.

Okay. Well, thanks, Sital. And so with that, we're going to turn it over to Tom Martin who's President of KMI. And he's going to go through our other business segments and the opportunities that we have there and just the overall set of opportunities that we have at Kinder Morgan.

Great. Thank you all.

Listen, I'm going to parlay some of my discussion here in a minute to highlight what that all might lead to -- build up to over time. But it's really starting with the strategy and execution. We've had the same strategy here at Kinder Morgan of being -- investing in, owning and operating core energy infrastructure critical to the U.S. economy. And great example of that, of course, is our natural gas network of 70,000 miles, and we serve 40% of the market. Additionally, our products and terminals infrastructure that serves refined products to key markets in the West, Southeast, New York Harbor and the Houston Ship Channel is also very critical to the U.S. economy. As far as commercial focus is concerned, we focus on stable fee-based assets. As we've discussed before, 68% of our cash flows are take-or-pay or hedged. We focus on long-term contracts. There's actually a slide in the appendix on Page 121 that gives you a breakdown by business unit of what's the percentage of take-or-pay is and what the contract tenure is. But just as an example, in our natural gas interstate business, we have an average contract tenure of about 6 years important to us. Financial discipline, very strong balance sheet with a lot of flexibility and very important to us. We self-fund our capital projects, and we have a growing dividend that's well covered while we've had -- we've been operating at just around 4x debt to EBITDA for the last several years. And during that time, we've been able to execute on very strategic acquisitions as well as doing share repurchases. So again, all of that centered around financial discipline. And then as it pertains to capital allocation, we invest in projects with returns that are well in excess of our capital costs. We target about a 15% after-tax unlevered IRR, but we adjust up or down depending on the risk profile of the project. Creditworthiness, contract tenure and the overall -- we don't go below low teens on -- just to make sure that we're well above our cost of capital. And then shareholder value focus. We returned significant cash flow to investors through dividends, opportunistic share repurchases and attractive M&A activity. As Rich said earlier, we've spent $16.3 billion or delivered $16.3 billion in dividends, $1.5 billion in share repurchases since 2016 while paying down $8.3 billion of debt, all of which is leading to shareholder value. And so moving on to high quality natural gas-focused cash flows. So 64% of the cash flows in the company are from our Natural Gas segment. Of that, 89% is from transportation and storage and 11% from G&P. To put it in perspective, 57% of KMI's earnings is from transportation and storage. So just a significant part of the company and a great growth story, as you just heard. 89% of the natural gas transportation and storage is take-or-pay and average contract tenure of 6 and 4 years for transportation and storage, respectively. And a key point that many may not know is that KMI's percentage cash flow contribution from our long-haul natural gas pipelines is greater than any other large U.S. midstream company. So moving on to the backlog. At the end of 2023, we have $3 billion in our backlog. We put $1.8 billion worth of projects into service during 2023. Of the $3 billion, if you peel off G&P and the EOR projects, we have about $1.9 billion worth of projects at $4.6 billion -- at 4.6x multiple. A key point is about 80% of our backlog is low carbon investment, which is primarily natural gas, but also investments in energy transition ventures and then renewable projects within our products and terminals business. In 2024, we have about $450 million of EBITDA from the first full year of projects that we put into '23 and a partial year of projects that we're bringing into service in 2024. And we expect about 50% of the backlog is going into service in this year. So just a bit of a look-back analysis here, which I think really drives home the key point. We looked back on a 3-year multiple basis and a 5-year multiple basis. Capital that we've invested in a 3-year window of $2.8 billion on a 5-year window of $6.2 billion in both instances, extremely attractive return multiples. Really, the variation is depending -- is hinging on the scale of the projects that we put into service during those periods. The 5-year look-back includes a major mega project like Elba LNG and ship loading, which is $1.2 billion and also GCX during that period. Permian Highway project is actually in both of these windows. But if you sit back and think about what was going on in that 3-year and 5-year window and the incredibly challenging project execution environment that the industry and Kinder Morgan was in, we had a steel tariff in the early part of that period. We had COVID, of course. Inflation creeped in during the middle part of that period. Supply chain issues evolved and then really throughout that and an increasing challenge in getting permits during this period. And so just a tremendous effort and evidence really of our company's ability and discipline around scoping, commercializing, sanctioning and executing on projects. We do what we say we're going to do, and I think this is a pretty good evidence of that. So we've talked about a lot of projects that we brought into service. We're bringing in more this year. What are we going to do next? Well, I think we've told you before that we're very confident that we're going to spend over the next several years, the high end of our $1 billion to $2 billion a year in growth capital. And I think you get a sense of that from what we just heard from Sital and Kim. Natural Gas is going to be a major part of that story with all the things that we just heard. LNG, Southeast being short of supply, exports to Mexico, storage, industrial, power and Permian egress. In addition, the renewable opportunities that we're seeing in our terminals and products pipeline business as well as our growing Energy Transition Ventures group. So all told, we see an opportunity set over the next several years of anywhere from $4 billion to $10 billion. And we think about 90% of that is in the natural gas sector. Now listen, we're not going to get all of those projects, but that -- I think if you absorb the themes that Sital and Kim were talking about, especially in gas, there's a lot of opportunities and the position of our network gives us a great advantage to get more than our fair share of these opportunities, we think, over the next several years. So moving on to Natural Gas. It's going to be really brief here because this has been well covered. But I mean, if you -- it's a great footprint. Having been in the gas business for 20 years, it's -- continue to be amazed with what we deliver from our network here, connecting to all major supply sources and demand centers, our market position of 40% of the market. And we're really seeing high demand and utilization of our storage and pipeline assets. And the consequence of that is we're getting higher rates, where we have the ability to charge them. We're getting longer-term contracts, and I think you have information in your appendix that shows that we're -- contract tenures going up. And then we have a tremendous project opportunity set from these growth trends. So Sital talked a bit about the South Texas acquisition from NEP. I'll give just a few highlights of it. 462 miles of long-haul gas. Pipeline's was 4.9 Bcf a day of transportation capacity. Very synergistic with our footprint in Texas, both with the Texas Intrastates as well as Tennessee Gas and NGPL. Gives us some flexibility to provide more nitrogen blending opportunities. We think it will be very capital efficient on projects that we've yet to in that we may be able to provide the same capability at lower cost with not having to spend as much capital. It's a fee-based business with 75% take-or-pay and a contract tenure of just over 8 years. So again, it fits extremely well with our Texas footprint. And Sital alluded to this. And again, my experience in the gas group within Kinder Morgan is that the acquisitions that we've done that are highly integrated with our existing network, we end up, over time, create -- finding more value, more opportunities to create value that we never contemplated when we actually made the acquisition. And I think we're likely to see the same situation here with this asset acquisition. So now flipping to the Products Pipeline segment. We're the largest independent transporter of refined fuels in the country, largely serving the West Coast and Southeast markets. We have 56 million barrels of associated -- capacity. Average volume around 2.2 million barrels a day, of which 75% is refined products and 25% crude oil. New to the asset fleet is 77,000 barrels of RD capacity. I'm going to speak more to that here in a minute, but really a strong moat position in the products segment. And then looking at just cash flows, very steady performance in cash flows and also volume throughput. We did have the dip in -- during the COVID period. But in the refined products business, we really see fairly flat volumes over time, but we see a slight increase in earnings due to our rate escalators -- FERC escalators that we have in our refined products. So I think the best way to think about our Products Pipeline segment is a steady cash flow contributor with low capital cost with upside from the renewable trends that we're seeing, really just kind of reinventing ourselves in these markets out West, and I'm going to speak more to that here in a second. So the renewable diesel story has been a great one. It's been very capital-efficient opportunity for us in the products group. We saw this opportunity first in Southern California then evolved in Northern California. We're the first company actually given, again, because of the footprint that we have and the connectivity that we have. We're the first company to transport RD via pipeline to market in the United States. It's a great first mover advantage. We have $60 million worth of RD projects that we put into service in 2023. We have about $20 million in our backlog currently. And we're exploring additional opportunities in the Pacific Northwest, namely Washington and Orange -- Oregon. So tremendous additional opportunity within a very stable business. Moving on to terminals. We're the largest independent terminal operator in the country. Also very stable earnings with low capital requirements. High take-or-pay percentage of our business, about 70%. And 70% to 75% of our contracts have contractual escalators. So again, a very stable, low capital-intensive business. About 56% of our terminals business is liquids, 18% is Jones Act, 24% bulk. And we also seen some nice growth opportunities from the renewable story in the terminals business. A key part of our terminals business, about 51% of the EBITDA from terminals is in our liquids hub areas, key liquid hubs. And what we've really been able to do over time is build very irreplaceable, honestly, hubs with a focus on key markets that provide storage services to tank -- to our customers that participate in market volatility and import and export opportunities. So it's -- we're seeing very high utilization in these key hubs at the Houston Ship Channel, in New York Harbor, New Orleans, Chicago. 97% utilization, which because they're so highly utilized, we've been able to leverage that into higher rates as we go forward. Terminals is also participating in the renewables story through feedstock storage. We're the largest handler of renewable feedstocks in the country, 1.6 million barrels of capacity leased for renewable feedstock storage across our network. The biggest position is in New Orleans. But again, we have it in Chicago, New York and Houston as well. So really utilizing our existing network towards capital efficient, attractive returning projects supporting renewable growth. Key area in New Orleans, we're investing about $135 million in multiple projects to expand our lower Mississippi River hub area. So again, in closing on terminals, very stable cash flows. We're actually seeing nice growth in our base business while we're participating in renewable project opportunities at a very capital-efficient way. So moving on to CO2. World-class, fully integrated assets, consistently generating robust cash, free cash flow, as you can see in the chart. We have made an acquisition in 2023, Diamond M, which is adjacent to our SACROC field. So it's a nice bolt-on opportunity to grow, and we feel very comfortable with the geology there since we have so much success at SACROC. We've invested about $180 million in EOR project there that's in our backlog. And we expect oil production from that acquisition to grow by over 5,000 barrels a day in 2026. In addition, in our CO2 segment, which is important for the renewables front is we're the largest transporter of CO2 in the country. Significant CO2 pipeline footprint in West Texas. So the experience that we have on the CO2 side of EOR and transportation will lead us to great opportunities in our Energy Transition Ventures business, which I'm getting to now. So starting with ETV, we made three acquisitions in RNG to establish our strong footprint there. We brought three facilities online in 2023 and expect a fourth online in the second half of '24. So when fully in service, we'll have up to about 6.4 Bcf of annual RNG capacity -- production capacity. And we expect the first full year, multiple of about 6x in an investment between acquisition and expansion capital of about $1.1 billion. So that multiple is very favorable to what we're seeing in RNG M&A space as of like many of those transactions have been at 10x where we're buying and growing internally here at a 6x multiple. So very attractive. And then on this carbon capture side, we're bringing -- expect to bring a Red Cedar project into service late in Q4 '24. We're seeing a lot of activity pick up there on the CCS side, both as it pertains to our network in West Texas as well as off-system opportunities. And again, the expertise that we bring from our CO2 business is going to give us an advantage in being able to participate in that opportunity set as we go forward. So in closing, I think you'll agree that there's many ways in which we deliver shareholder value. We're natural gas focused. We have a strong balance sheet, high returning projects, predictable and growing cash flows, all of that yields to substantial shareholder returns. And so with that, I think we're going to take a 15-minute break and then we're going to have a panel discussion with the product pipeline, terminals and CO2 business unit Presidents. [Break]

Welcome back, everyone. So the current segment -- next segment of the -- the presentation is our panel discussion with Anthony Ashley. He's the President of our CO2 and Energy Transition Ventures group; John Schlosser, President of our Terminals group; and Dax Sanders, who's the President of our Products Pipeline group. And so the first question, we've talked a lot about renewable opportunities throughout this segment so far. And I think what I'd like to ask each of the panelists is beyond RNG, where do you see opportunities in renewables and how do prospective return to renewables -- returns for renewables compared to those in traditional midstream markets. So we'll start with Anthony and then Dax and then John on that.

All right. Thanks, Tom. Yes, Kim has mentioned earlier, energy transitions take a long time. And really, we're increasing global energy demand over time. We obviously, see increasing demand on oil and gas side of the fence for the next couple of decades. Kim showed you the chart earlier from the EIA. And in that scenario, carbon capture and utilization and storage CCUS becomes a vital piece to making our climate goals globally. And so these have indicated that we'll need up to $300 billion of investment in the U.S. by 2050 to meet a net zero target. Now Kim showed you some data on studies. And so we all know they have a lot of assumptions in those. But even if that's partially correct, that creates a huge opportunity in CCUS. And we think we are very well positioned as both Kim and Tom told you to participate in that business. We are the -- one of the largest CO2 pipeline networks in North America. We have been safely transporting and injecting CO2 in the ground for decades. And I will say, obviously, CCUS has been slower to develop. There's no easy buttons here. What we're doing is creating brand-new commercial arrangements. We're navigating complex permitting of regulations and time lines. With regards to some of the more diluted sources of CO2. Those need to scale. We'll need to see some lower capture costs in order for some of those projects to be economic. But bottom line is we do think that over time, we think there's an enormous opportunity here for Kinder Morgan in the CCUS space, and we think we're very well positioned there. With regards to returns, while we are very willing and able to participate in the capture side of the business, most of the projects that we have been working on and moving forward where the transporter or either that or the transporter and sequester of the CO2. With that in mind, that's really -- we view that as a midstream like service and should go on a midstream like returns. And so that's what we've been targeting. I will say to the extent that we're asked to take on any additional risk on top of that. We'll, of course, be elevating those return thresholds to accommodate that. So I'll turn it over to Dax.

Thanks, Anthony. I'm going to start with the return aspect, which similar to what we've seen in other pieces of our brownfield business, which our term -- our renewables piece on our products are largely brownfield modifications. The returns are just as good, if not better than we see around the rest of our business. And so that's something that I think we've seen as a real positive, very capital efficient. We told you back in January 2021 that we thought we would spend somewhere in the $50 million to $100 million range on West Coast renewable projects, and we're right in the middle of that right now. And I think we're going to see some additional opportunities to put some additional capital to work. But returns are, again, just as good, if not better than we see in our traditional midstream business. With respect to opportunity, the first opportunity is incremental utilization of the capacity that we have. Tom alluded to this, but we've got roughly 50,000 -- 57,000 barrels a day of hub capacity in Northern Southern California. In 2023, we did about 17,000 barrels a day throughout the year. Those barrels ramped up, but we did about that on those hubs. And so we still have a bit of a ways to ramp up compared to where we left it in 2023. We're seeing right now in January, volumes in the mid-30,000. So we're ramping up. And as we've said, the economics of these are underpinned by take-or-pay contracts. So it's not dependent upon the volumes to actually flow but the volumes are flowing. And one of the big catalysts we're seeing, as we've talked about are these Northern California refineries, Marathon and P66, Martinez and Rodeo. Those are doing somewhere in the high 20,000 barrels right now. But as they completely convert, they'll be up to 100,000 barrels a day, and we expect that the majority of those barrels. We'll start to move on our pipes -- continue to increase moving on our pipes and push barrels that are coming from the Mid-Continent Westward back. And again, those barrels will flow. So -- and again, we've got -- as I mentioned on the call, we've got the ability to expand those hubs further as they become more fully utilized. The other opportunities we have on the West Coast are Oregon and Washington State. Both of those places have well-developed LCFS models and shippers are very interested in volumes in those places. I think we will have an R&D conversion project in Oregon this year, I feel pretty confident in that. I think there's a good chance that we may have one in Washington as well. And so those are moving along. We've always got the possibility of converting our chemical facility in Richmond -- Richmond, California into a feedstock facility. We've had lots of conversations on that. We haven't actually gotten to something that works for everybody, but that's a possibility as those refineries continue to develop and convert. And then there's always sustainable aviation fuel. As you know, California has got a proposal out that would potentially change the inclusion of jet fuel in the LCFS program, which could increase the demand for it. And as with everything else across our portfolio, if our customers want to do it, we'll be there with the capacity and step up and help them. So those are the opportunities.

Great. Thanks, Dax. I'll start off with answering the question why. Why would the customers want to do business with us and the price of an admittance for us in the Terminals group is really threefold. And when you think about it, we're 100% unregulated. And so we have to delight our customers each and every day or as those contracts come up, they're going to walk down the road and do business with our competitors. And by delighting them each and every day, what we're also seeing is a multiplier effect. They ask us to come in on project after project after project behind that. And you're seeing that with the NESTE projects with some of the Chevron projects and a number of others, that was mentioned earlier. The second piece of that is our experience. We are the largest handler of ethanol. We're the largest handler of biodiesel. We're the largest handler of renewable diesel. We're the largest handler of feedstocks, gasoline, distillate, jet, you name it, we're the largest handler of it. So we have the experience and customers are looking for that. And the last is great bones. Up there is our Houston Ship Channel assets. and as was mentioned earlier, unreplicatable, but if you translate that across our entire terminal network, think about it, 74 terminals, 79 million barrels of storage, 266 docks, 462 truck base, 6,800 railcar spots, countless inbound lines, countless outbound lines. It will always be cheaper, easier and faster to convert existing assets than to build greenfield projects. So for our standpoint, our focus is on a number of different product classes. First and foremost is feedstocks -- next one. And we've invested, as was mentioned, $130 million in this space. It's in its infancy. We're likely to see more opportunities pop up across the network. This is a very high-value commodity with special handling requirements and always commands a premium rate. So this is our NESTE projects in Harvey, our Chevron project at Geismar, NESTE project at Carteret and a number of others. The next product is RD. We're seeing demand for RD across our network outside of California. This is a drop-in product at more attractive rates than we get for traditional distillate tankage. And as Dax mentioned, the last one is SAF. This is really the next big wave, not much to speak of today, but it's coming. We see opportunities outside of California. An example is Illinois implemented a state tax credit, which we'll see a demand pull to Midway and O'Hare, which, by the way, were connected directly to Midway and we're direct connected through the Buckeye Pipeline to O'Hare. So we're seeing a lot of interest on SAF, producers, traders, airlines, et cetera. And as you know, SAF requires blending. You have to add Jet-A into it, and we're seeing a lot of requests for 30-70 splits, which means more tankage, more opportunities there. And the last piece -- to the next one -- is our -- back at our Houston asset, we have the ability to pipeline deliver to 6 of the top 10 largest airports in the United States. And we also have a very, very deep pool of Jet-A for blending there. So if you're a SAF producer, think about it from a purely a logistics standpoint, you want to be at that hub because you know that from an optionality standpoint, you can get anywhere with your molecule. So the last piece is the part that Dax started off with is our returns. Because we're using these great bones of our asset and converting it, it's much more efficient. Usually what takes place is we're reactivating historic distillate tanks. We're putting new pipe in, heat tracing and building new loading racks. So for the most part, very efficient and very good returns on each of these projects.

Yes. So as you can tell, there's lots of opportunities around renewables in all 3 of these business units. Second question is for Anthony on CO2 and ETV. What is KMI's appetite in competing for RNG offtake in the voluntary market to insulate your earnings for future D3 volatility? And what is driving your optimism for D3 pricing?

Yes. Thanks, Tom. We strongly believe in the fundamentals of the RNG business, obviously, made 3 acquisitions in that space. It is a finite resource. We do fundamentally believe that it is a cheaper way to decarbonize than electrification for most companies. We are, however, fully contracted into the transportation space right now with our existing assets. And that -- what that means is we generate a D3 RIN that together with the underlying commodity is worth about $40 per MMBtu, which obviously is significantly higher than brown gas but also higher than what we could achieve in the voluntary market right now. And so what we've seen in terms of voluntary market is deals in the $20 to $25 per MMBtu range. Now we do think that this discount is going to close over time. It has to close over time as the voluntary market grows, and we think that market will easily eclipse the size of the transportation market over time. We'll have additional opportunities at a later date to recontract into that market if it's attractive for us and decision point at that point in time. With regards to D3 RIN prices, we do think there's solid fundamentals for those prices in the near to medium term. The EPA issued its renewable volume obligation back in June of last year. And what that came out with it was effectively a 30% increase in the D3 requirement under those RVOs for -- each year for the next 3 years. So it's the first time they've come out with a 3-year requirement. And then in addition to that, what used to be the case, you used to have what was called a cellulosic waiver credit available in the market. That's no longer available. and what that CWC credit effectively did was served as a price cap for D3 RIN prices in case of excess demand, that's no longer in place. Also, the EPA in their original proposal in December of 2022, opened the door for eRINs being part of the RVO. That didn't eventually make it in there. But because it was in the original proposal in December, the effect of that was that producers, including ourselves delayed the conversion of some of the landfill gas to electric projects that they own to RNG projects. And so there's less supply effectively coming to the market than was originally thought. And what they also did in June of last year as they changed some of the rules around RIN certification and RIN compliance. And so what will -- that result would be [ as ] effectively some renegotiating of existing documents and contracts in the space. And also requires all parties within the R&D value chain to register with EPA. So we do think that this is going to delay some of the RIN certification and potentially even push some of that volume into the voluntary market and out of the transportation market. We've obviously had some supply chain issues as well. What that's done is extended some of the time lines associated in these RNG projects coming in service. So if you put all of that together, effectively, what that means is less supply than was expected coming to market, more demand because of the increases in the RVOs and no price gap. So we think there is solid support for D3 RIN prices in the near to medium term.

Great. Thanks, Anthony. Now a question for Dax in products. In light of the upcoming recontracting for multiple Eagle Ford crude pipes in the next couple of years as well as potential expansion. What is your outlook for KMCC and Double Eagle?

Yes. So KMCC was definitely a pipeline that was built in a different area and anchored by pipeline contracts in a different area. Those contracts have all rolled. And so we've seen the legacy pricing on that rollover. KMCC is a pipe that now is flowing barrels at a market rate. We've got 72,000 barrels a day of take-or-pay contracts with a duration of 2 to 2.5 years. We've also got incentive rates with those third parties that had sent additional barrels to flow. We've also got about 75,000 barrels a day of capacity held by our marketing affiliate, which utilizes that as well. KMCC is a key pipe. It's one of really only 2 pipes that connect the Eagle Ford to the Houston refining complex. And it's a key conduit for our 100,000 barrel a day splitter facility that we have, which runs sort of right at that level. So it's -- I think the overall summary is that it's a key pipe coming out of a key basin with contracts that are right at the market. And so we did on KMCC just below 200,000 barrels a day in 2023. The budget for this year is just over. So I think KMCC will continue to do something right in that 200,000 barrel a day range, again, at market rates.

Anything on Double Eagle?

Yes, Double Eagle, we just had contracts roll on Double Eagle. The legacy contracts on that sunset at the end of last year. We did recontract on that. We've got 25,000 barrels a day on that pipe contracted take-or-pay with incentive rates above that as well through the end of 2025. So that pipe is actually reset as well.

Great. Thanks, Dax. Next question for John. Terminals generated $1 billion in EBITDA fairly consistently last 4 years. Will it remain around this level going forward? Are there opportunities for growth?

Yes. So our EBITDA last year was up 6.6%. But I want to put that in historic context because I don't think this gets much press. Since 2010, our EBITDA has grown 62%. And during that same time period, we have sold half of our terminal network. So we have half as many terminals, yet EBITDA is up 62%. These were strategic divestitures, in some cases, they were closures and they generated $1.6 billion of transactional value back to Kinder Morgan that could be used for all of the things that were listed earlier. And so our budget for this next year is up modestly over the previous year. But we do see tailwinds, which will allow us to continue to grind higher. First of those is in the Jones Act. We see rates trending higher in this area. We have now surpassed our pre-COVID rates. We are seeing spot rates in the mid-80s, 80,000 a day. And because of the lag effect with contracts -- so during COVID, we purposely chose to make sure that all of our vessels were moving. So we entered into contracts, medium-term contracts with some of the majors, those are rolling off and, as you can see there, '25, '26 and '27. And we believe that rates will be appreciably higher as we recontract each and every one of those vessels. And that all flows to the bottom line. And so in most cases -- in many cases, we've already recontracted those on forward contracts. So we're very bullish on the Jones Act for a number of factors, Russia, Ukraine, PADD 3 to PADD 5 renewable diesel, we're seeing more volumes there, resiliency of Florida. But the biggest reason why we're bullish on it is when you think about replacing the existing fleet that's there today, and I'll remind you, we have the youngest, most fuel-efficient fleet in the Jones Act business. It would cost somewhere north for a Tier 3 vessel of $200 million. You would need to see rates north if you're looking at just a rational economic decision north of 100 a day in order to achieve that. So there's a lot of headroom in there as it relates to the Jones Act and our position in it, 16 vessels. Also from a tailwind standpoint, fundamentals in our key hub markets, you're seeing rate appreciation in Houston, but even more so in New York Harbor. Our refined product exports. We have, as I mentioned last year, we have 50% upside in capacity there with no additional capital needed. So there's a great opportunity there. And then we have our expansion projects, which are the renewables, blending components and supply optimization at a number of our hub facilities. But overall, we're very optimistic for continued growth within this segment.

Great. Thanks, John. Anthony, next question for you, and we've touched on this a bit, but maybe you can just expound on this. How has the carbon sequestration project development progressed in the last year? And where do you see the opportunity set kind of going forward?

Yes. We talked a little bit about the Red Cedar project. We announced that earlier last year, that project continues to progress. And just a reminder that Red Cedar is a JV between the Southern Ute Tribe and our midstream affiliate. And what they're looking to do is capture up to 400,000 metric tons a year of CO2 of the 2 natural gas processing facilities that they have. And then what we will be doing is transporting that CO2 on our existing infrastructure and then permanently sequestering that CO2 in West Texas. We do now have -- the EPA has approved our MRV plan associated with this project. We are waiting for approval from the Texas Railroad Commission on our modified Class 2 permit. But right now, we are on target for this project to be in service in the fourth quarter of this year. And then I would say in addition to that, there are several other interested parties in West Texas that are looking to do effectively the same thing. Capture off of their natural gas processing facilities and that we would be effectively the transportation and sequestration party using our existing infrastructure. And those are in various states of negotiation, but are advancing nicely. So I'd say that we have with regards to opportunities around our existing infrastructure, some smaller scale opportunities that could be online in the next 1 to 2 years. And then our off system that we are working on a number of other projects, which are larger scale that will require Class 6 permits. So the longer development cycle permits, many of them will need additional infrastructure and in those situations, we're looking to be either as said, the transporter or the transportation and sequestration party. They -- they're a little bit more challenged on the economics because -- and so they need to scale up. But looking at probably FIDs up to you maybe a year or so out and in service later in a decade. So that longer development projects -- so our near-term opportunities are around our existing assets. But we're really excited about the number of opportunities that we are seeing developing in the space. But as I said, they will take some time to develop.

Great. Next question is relative to PADD 1, and this is really for both John and Dax. We'll start with Dax. Following PADD 1 closure of refining capacity even before the pandemic in multiple European refinery -- refineries closed. The outlook for PADD 1 product supply looks tight and inventories could be volatile, will this translate into structurally higher utilization of plantation?

I think the answer is yes. The product Southeast pipeline is a key conduit from PADD 3 Gulf Coast refiners, most specifically Exxon Baton Rouge and Chevron Pascagoula into PADD 1. And so it is a good pipe in the ground. That's a key supply conduit into that market. And as the refiners there go away, the PADD 3 refiners aren't going to go anywhere. So that increases the value of that conduit. Colonial is -- given that it goes all the way to the harbor, is generally going to be the first pipe to fill up. However, it's on allocation. So product Southeast is a very advantaged pipe. It's got connectivity to several markets, including Reagan National Airport in D.C. where it really is the sole source of supply. So I think it's also got connectivity to Colonial in Collins, Mississippi. So I think it will be a key conduit between those markets and it will benefit as PADD 1 refining continues to be disadvantaged to PADD 3 refining.

I'll tag on to that as we're the end of the line in New York Harbor. We have a tendency to like chaos. We like the inventory and pricing volatility. It usually means more tankage opportunities but there's a structural change that's going on in New York Harbor. Over the last number of years, 10 million barrels of storage have come out of that market. That's roughly a 51 million-barrel market. 10 million barrels have come out. We started the ball rolling when we sold our Staten Island facility, which is 3.5 million barrels for a land use. Buckeye Newark, Buckeye Raritan Bay at 3.5 have been sold. IMTT Bayonne Central Plant and announced IMTT Bayonne East Plant, another 3 million barrels have come out of that market. And it's been rumored, though we won't comment on it. [indiscernible], it could be a potential target as well. But so given today's permitting and environmental justice issues, it is highly unlikely you're going to ever see another barrel storage built in the harbor there. And we are uniquely positioned as the largest handler and blender of gasoline in the harbor to continue, specifically at Carteret to continue to see opportunities within the harbor there.

Great. Great discussion, guys. Thank you. With that, I'll turn it over to David Michels.

All right. As we're getting resituated here, I'll go ahead and get kicked off with our capital allocation priorities. So it all starts with an advantaged set of assets, advantaged portfolio of assets that we've heard a lot about today, mostly backed by long-term contracted cash flows, long-term contracts that generate highly stable cash flows. Next is our balance sheet. We think it's important to have some leverage in our capital mix to reduce the needs for the relatively high cost of equity to fund our operations but we need to make sure that we have the appropriate amount of leverage in that capital stack. And we think given our credit profile and our overall business mix, we think it is appropriate. So with that fundamental backdrop, then we layer on top of that a very disciplined established approach towards allocating capital to investment opportunities. We tend to target -- we do target a 15% unlevered after-tax return for our projects, and then we vary that threshold for return based on the risk profile of the individual opportunities that we're evaluating. That high threshold for return or we think it's a pretty high threshold for return typically results in us generating more cash flow than opportunities that we invest in, which leaves us with a very high degree of free cash flow. Then we believe in returning a lot of that cash flow to our shareholders. Our stable cash flow enables us to commit to a regular and modestly growing dividend. And then finally, we'll evaluate the opportunity for share repurchases. We think the appropriate way to look at share repurchases is on an opportunistic basis. And what that means is -- we don't just have a pure programmatic approach to repurchasing shares. We'll wait for an attractive price to repurchase shares. And we think that's wise, and we think that's worked out very well for us. So looking at a recent track record of our performance. Since 2016, we've generated EPS growth rate of 8% on a compound annual growth rate basis. We've reduced our leverage by 26%, and we've returned over $20 billion of value to our shareholders. So the bottom line here is we've got an advantaged set of assets run by very committed professionals. We've paired that with logical financial priorities and strategies, and that's resulted in a very strong financial position, and we've created tremendous value for our shareholders. And that performance is important, we think, because it demonstrates that Kinder Morgan is doing what we said we were going to do. We're following the capital allocation priorities that we've said we would follow. So on the next slide, some of you have noticed that we haven't -- have said that we haven't grown our EBITDA that much in the recent past. And to some degree, I think that's true. But when you take into account the amount of divestitures that we've achieved over this time frame, you'll see that we've actually divested assets that contributed $700 million of EBITDA back in the 2016 time frame. Those divestitures have generated good proceeds that we've used to greatly reduce our leverage, which achieved some of the leverage reduction that we talked about on the prior page. And when you take those divestitures into account and just look at the remaining assets, EBITDA growth over this time frame, it's 26%. So a pretty nice growth rate, especially for a company our size. All right. So now moving into the 2024 budget. This is consistent with the budget that we talked about last week at the earnings release except with a lot more detail. And as usual, we're going to post this budget -- we have posted the budget to our website, and we're going to refer back to it all year to hold ourselves accountable and allow you all to hold us accountable as well. So our budget is to generate EPS of $1.22 per share, a nice 14% increase from 2023. We're budgeting to grow both adjusted EBITDA and DCF per share at an 8% clip versus last year. Our leverage is budgeted to be below 4x at 3.9x at year-end 2023, 2024. And we continue to expect to pay out a very healthy dividend at $1.15 per share. We don't have any share buybacks in the budget, again, because of the opportunistic approach that we take to share repurchases. We can't be guaranteed that we'll have an attractive share price to repurchase that. All right. To go through a guidance reconciliation from -- if you remember back in early December, we provided a high-level guidance summary for 2024. There -- the big change between that guidance and the final budget that we released last week and that we're talking about today is the South Texas midstream acquisition that we achieved right at the end of the year last year. So this is just another opportunity for us to illustrate just how nicely accretive that transaction was $0.01 per share immediate accretion on EPS, $0.05 per share accretion on DCF. And -- and I think Sital had an opportunity to talk a little bit about how excited we are to have those assets in our portfolio and some of the good opportunities that we expect to be able to generate using -- having those integrated nicely with our existing assets. All right. Moving on to our EBITDA bridge. So for 2023 actual to our 2024 budgeted adjusted EBITDA, an 8% growth there. You can see in this first category, this is really a number of individual items that are all contributing to a slight reduction. The biggest of which is CO2 EOR oil production volumes being slightly down relative to 2023, but there are a number of other items in there as well. The next category is where we put all of our favorable recontracting and unfavorable recontracting plus our rate escalations all into one bucket. And you can see it's a nice slightly favorable net adjustment to our EBITDA. So net-net, with those 2, that's really kind of same-store sales, we're basically flat on same-store sales, a little bit down, but basically flat, which is nice, is kind of consistent with the theme that we started last year, saying the big recontracting headwinds that we had to endure for some time is they're behind us and the base business is much more stable than it's been in the past. Then we talk once again, and I'm sure Kevin Grahm is going to be happy about this. We're talking about the South Texas midstream acquisition, once again, $200 million of additional EBITDA contributing to 2024. And then our growth capital project contributions of about $400 million, and that brings us to the 8% higher adjusted EBITDA year-over-year. In the next slide, we'll talk a little bit more about EPS and DCF per share. EPS is budgeted to be $1.22 for the year, the same as our adjusted EPS. The only difference between EPS and adjusted EPS are the certain items. We don't have any budgeted for 2024, and we had a small amount that netted to a small amount in 2023. But the main point is our earnings per share, whether you're using earnings per share or adjusted earnings per share are growing very nicely in 2024, either 14% or 15% growth year-over-year. So very nice double-digit growth and DCF per share, as we said before, $2.26, up 8% from 2023. Our dividend expected to be $1.15 per share. That's a 2% increase in our dividend. And so that's growing slower than the rest of our cash flow measures, which means the dividend is going to be more well covered and more sustainable for the long run. Next slide is our adjusted EBITDA slide. This provides a lot more detail on main changes in each segment from '23 to the '24 budget. I'm not going to go through this slide in detail, just to -- just point out that it's nice to see growth in each one of our business units. In interest expense, that's higher. This is completely explainable by the higher debt balance that we have in 2024 versus 2023 on average, primarily driven by the acquisition that we achieved last year. Sustaining capital, we'll go through that in the next slide. So I guess going on to the next slide. Sustaining capital is higher by $150 million. Most of that is driven by higher regulatory obligations in our natural gas business. The main categories are an increased number in the class location changes that we need to address in 2024 versus 2023, higher cost to comply with additional environmental regulation, primarily air regulation in 2024 and higher costs related to reconfirmation of operating -- max operating pressure required under the Mega Rule. It also includes incremental turbine exchange costs. So as we've talked about, our pipelines are more fully utilized these days, which requires more frequent exchanges of our turbines. It's a little bit of a double-edged sword. On our discretionary capital, our budget is $2.3 billion mostly in their natural gas pipeline area of $1.75 billion there. The 3 individual natural gas pipeline projects that are highlighted here all sum up to about $700 million. The rest of our projects in natural gas and in our other business units are primarily relatively small projects, highly capital efficient. We've heard that term a lot today, strong returns, capital efficient, relatively low profile and constructible. So all very, very positive. And as Kim noted earlier, across the backlog, we expect an EBITDA multiple of below 5x. So very attractive returns. Moving on to our cash flow from ops. So this slide walks from net income down to our cash flow from operations, then we deduct our GAAP CapEx, so that CapEx, including our sustaining capital piece to get to free cash flow. Free cash flow of $2.8 billion, subtract out our dividends paid. We get to just over $200 million of free cash flow after our dividends. One thing to point out here is in 2023, we had an $835 million contract prepayment. And I want to point out that we are going to continue to recognize the EBITDA associated with those contracts going forward. However -- and that's consistent with the GAAP guidance that you recognize revenue when services are rendered, not when the cash flow is received. So we're going to continue to adhere to that GAAP guidance. However, if we were to exclude that EBITDA component from our leverage calculation, the adjustment would -- for 2024 would be at 0.036x net debt to adjusted EBITDA delta. So it's a relatively immaterial number, but I wanted to bring it to your attention. Moving on to our sources and uses. This is a very high-level summary of what we expect for 2024. So on the sources side, we're going to -- we expect to generate $5.8 billion of cash flow from operations. We had a small amount of cash on hand at the beginning of the year, plus we received distributions from equity investments outside of cash flow from ops in our cash flow from investing segment of the cash flow statement. So that leaves us with an additional borrowing need of $1.7 billion. On the uses side, and we've already covered CapEx, and we've already covered dividends. So the remaining piece, really, the big remaining piece is our debt maturities for 2024, which are $1.9 billion, and they're spread out pretty nicely across the year. So quite manageable set of maturities for 2024. I would also point out that we came into the year with about $2 billion of commercial paper outstanding. And so at some point, we would plan to term that out as well. Okay. Moving on to the liquidity slide. So as we said, we expect to end 2024 at 3.9x and on the right-hand side, you can see what our debt maturities look like on a kind of go-forward basis for the next several years, quite manageable. This is much lower than what we've had to manage in the recent past. And so we're pleased to see this. I'd also note that in 2023, I know many of you are interested in this, our floating rate swaps or the portfolio of floating rate swaps declined a bit. We went from $7.5 billion down to $6.2 billion. We just had a number of swaps that matured, and we chose not to replace those given the economics around replacing those in the year. We still think that those swaps provide a lot of value for the company. We've earned prior to 2023, $1.2 billion of lower interest expense the decade prior associated with our floating rate swap. So we still think that's an appropriate item to have in our capital mix. And we'll just -- we'll just remain flexible on that going forward based on market conditions. All right. Our 2024 quarterly profile, we provide this to you all every year so that you can recalibrate your quarterly estimates for us. Our yearly results are not evenly distributed across the year. And that's primarily driven by the fact that our natural gas pipelines generate greater revenue and greater margin in the first quarter and the fourth quarter because of stronger demand for our services in the winter periods. We also have greater estimated tax payments in the second quarter and we have 0 estimated tax payments in the first quarter and just one each in the third and the fourth. And then finally, DCF is further impacted by lower expected sustaining capital in the first quarter. So we've provided you with this information. We encourage you to take that and put it into your models, please for your modeling benefits. All right. To wrap up, we're very excited about 2024 and the foreseeable future for Kinder Morgan. Our focus on natural gas commodity with fantastic tailwinds that we've already talked a lot about. Our balance sheet is the strongest that it's been in a decade. We continue to find a highly attractive set of projects to invest in, not just the $3.5 billion in our backlog, but also a very robust pipeline of projects beyond that. Primarily focused on the favorable trends that Sital and Tom covered and Kim covered in the natural gas space. Our cash flows are nearly 70% take-or-pay or hedged backed by long-term contracts. Our cash flows are highly predictable. And then finally, we are a company run by shareholders for shareholders with a great bias to return, create and return value to our shareholders, primarily in the form of a healthy dividend, but also with share repurchases. Furthermore, I think it's intriguing to think about a company like ours that's yielding 6.5% and is growing at the pace that we've been talking about here from a total return standpoint, it's pretty exciting. So we're very excited about the future for Kinder Morgan. And that completes my section. So now we'll turn it over into the Q&A portion of the presentation.

Okay. So with that, we'll turn it over to Q&A. I think we have mics. And so if you will raise your hand, we'll bring you a mic so the people on the webcast can hear -- got the whole management team up here to answer questions, and we've reserved plenty of time to make sure we get to all of them. So go ahead.

Theresa Chen from Barclays. First, I'd love to understand a little bit more about how you feel about the lean window of the Eagle Ford. What kind of resource potential do you see there? And if the WoodMac estimated 0.5 b per day is wrong for the broader region, how high do you think that number can go?

So Theresa, I think the half 0.5 b growth, we probably would project at 2.5 b of growth. I think the basin there has ample resource, especially in that Webb County area. So our view of the projection probably would be the plus 2 Bcf in the basin by 2030.

And as a follow-up to some of Dax's comments on the renewable diesel hub development. So seeing the conversions at the in-state California refiners, Martinez, Rodeo, et cetera, ramping higher and to your point, backing out the Midwest RD being shipped in. So one of the burgeoning demand center is Canada with the ramp-up of their clean fuel standards and some of those Midwest facilities being [ Dickinson ] [indiscernible], for example, maybe target that market. You have some products infrastructure in that region. Is this potentially an opportunity for an additional hub?

Yes. I would say we don't have any actual refined products infrastructure up there in the sort of Northern Mid-Continent, we've got crude infrastructure that's Double h Hiland. So I'm not sure that we would be well positioned to take advantage of exports out of the U.S/imports into Canada in that area. Now the overall Canadian dynamic, I think, could play positive for us. I mean, first of all, it could help. Certainly, what you're seeing in British Columbia could help exacerbate a project in Seattle/Washington state. But the other thing, I think the other -- and you sort of hit on this, the other big dynamic is any additional markets for those Mid-Continent American barrels that are being produced, I think will -- those barrels are all going to California, moving Westward to California right now to the extent that they start moving to other markets, whether it's Canada, whether it's East Coast markets, that will pull supply away from California and I think allow sort of Western barrels, whether they're Northern California refinery produced barrels, most likely or imported barrels to come in and move in one on our pipeline. So that's an indirect benefit, but I think it absolutely will benefit us.

Jeremy Tonet, JPMorgan. Thank you for all the information today, particularly on the natural gas side. And I was just curious if you could peel down a little bit further as it relates to the gathering volumes and just thinking about 2024, the outlook there, across your portfolio, how do you see gathering volumes trending by basin versus year-end '23 exit rate? Just wondering where you're seeing growth versus declines?

Okay. So just in aggregate, we're about plus 10% year-over-year on an average basis. But when you break it down by basin, really the Bakken, we see kind of flat, given the constraints until we get our residue project out. Altamont waiting on capacity, so likely will be flat to rising based on our -- some of the debottlenecking we're doing. KinderHawk in the Haynesville, we exited about -- this is, in the round numbers, 1.5 Bs. KinderHawk, put the winter, you put the weather winter aside, we expect that to kind of get back to that level until we get the next set of projects on, which are slated for midyear and later in the year. And that takes me to the Eagle Ford. So Eagle Ford, our view around the Eagle Ford is that we -- by the end of the year, we should be maximizing our processing capacity, which stands at about a Bcf on an absolute basis. So all of those relatively exiting, I think the only one that's probably growing is the Eagle Ford to kind of match up to our processing capabilities.

And just to put a finer point on that. If you look at where we exited the fourth quarter on gathering volumes, I think our 2024 volumes are relatively flat to that level.

Got it. And then, I have a little question on capital allocation. Clearly, a lot of room on the balance sheet with leverage where it sits relative to the targets. And just wondering if you could walk us through a little bit more kind of the current thought process as it relates to buybacks and M&A and CapEx. And specifically for the buybacks, is there kind of a cap that you're thinking about in a given year to leave room for M&A should an opportunity come its way? And does the capital plan, as it stands right now contemplate anything from the -- Good Neighbor rule? Just wondering how these things all work together.

And before David takes this, I would point out, my comment was in the aggregate, they're flat versus the fourth quarter. Different basins move differently.

Yes. For 2024, there is a little bit in there for the Good Neighbor plan. We think it's appropriate given the litigation that's outstanding so forth. With regard to buybacks, we don't have a hard, fast cap on the number of buybacks that we would consider. I mean I think you can look at where we've performed in the past and the measured approach that we've taken in the buybacks as an illustration or demonstration of kind of the approach that we like to take there. It's taken a long concerted hard effort to reduce our leverage to the point that we are at today, and we're going to be very patient with regard to utilizing that capacity because it's very easy to lever up. It's very hard to delever. So -- but I wouldn't put a cap on it because if we trade down to $5 per share, we'll be pretty aggressive with regard to repurchasing our stock.