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

Good morning, and welcome. I'm Rich Kinder, Executive Chairman of Kinder Morgan, and as usual, we look forward to this event to explain the Kinder Morgan story in a detail that I hope transparent way. We hope you come away from this morning's activity with a realistic view of what we look at as a very positive story for Kinder Morgan and its assets. Now we can't have any of these presentations without, of course, telling you that should be obvious to anyone that we will be making forward-looking statements, of course, and this is the warning to take it all with a grain of salt. We think everything we're saying is very accurate and very perceptive obviously, but then we're [ prejudice ]. Moving on, what I thought I would try to do today -- last year, I remember, I talked about the overall market for the kind of assets that Kinder Morgan has and specifically, the growth of commodities, the important role of natural gas in any reasonable story for the future of energy. But today, I'd like to try to look at Kinder Morgan as a third party might look at it in terms of would you invest in this stock and is it properly valued. And I think you have to start by looking at energy infrastructure in general. And we believe that energy infrastructure, particularly natural gas pipelines and storage really has a very long-term runway in front of it in terms of moving and storing the energy, not just today but up tomorrow. Now where does Kinder Morgan fit into all that? Most of you know this story, but let me just repeat a few facts for you. We're the largest natural gas transmission network in the United States. We have about 70,000 miles of pipeline. We move about 40% of all the natural gas consumed in the United States. And very importantly, and I think recent events have demonstrated this. Very importantly, we have about 700 Bcf of natural gas storage. That's the largest storage position in America and about 15% of the total U.S. natural gas storage. Now beyond natural gas, we also have our other segments, which are important contributors to the bottom line. We're the largest independent transporter of refined products in America. We move about 1.7 million barrels a day. We have about 10,000 miles of refined products and crude pipelines. We're the largest independent terminal operator in America. We have 140 terminals. We have 16 Jones Act vessels. We're the largest CO2 transporter in America. We have the capacity to move about 1.5 Bcf a day of CO2. We produce it in the Southwest Colorado region. We move it across New Mexico and move it into the Permian Basin, where it's used for tertiary recovery. And importantly, we think in the future, some of it, and we have 1 project now. Some of it will be used -- will actually be sequestered in wells in the Permian Basin and not use for tertiary recovery. And finally, we have a growing energy transition portfolio. Most of you, I think, recognize the forays rays we made into renewable natural gas, which we think has a bright future. When we complete the build-out of the facilities we've acquired, we'll have the capability to produce about 7 Bcf of renewable natural gas beginning in 2024. We're also involved in renewable diesel, both on the West Coast and the Mississippi River area. And we're beginning to take a position in carbon sequestration, and we've announced our first, albeit fairly small project in that area just as recently as last week. Now if you look at the overall mix of Kinder Morgan's EBITDA, as you can see, natural gas contributes almost 2/3 of our segment EBITDA. The rest of the EBITDA split pretty equally between our products, terminals and CO2 segment. Now when I invest, I always like to participate with somebody who has skin in the game. I'd like to have a management team or a co-investor who is looking at the investment the same way I am as a passive investor. And I think if you look at Kinder Morgan through that lens, it's pretty interesting. First of all, we have 13% of the company owned by the management and the Board. That's a significant portion of the company. We have, maybe more importantly, a great core part of our executive compensation paid in stock. In fact, as this slide demonstrates 68% of executive compensation is delivered in restricted stock. And I think that leads us to a really great amount of discipline in how we approach our business. We strive to be a low-cost operator, while of course maintaining safe and reliable operations. We have a very high return criteria that we look at. We run all our investments through that criteria. We internally fund our dividend and our CapEx, and then we work to return excess cash flow to our shareholders through dividends and stock repurchases. But I guess the real test, what you see on the right-hand part of the slide is what have we returned to our shareholders over the past several years. And you can see the left-hand portion of the gray area of that slide, we've generated about $34.5 billion since 2016 in cash flow from operations. We've also dispose of certain assets that we believe were not core to Kinder Morgan, and we've raised a little over $10 billion from that source. What have we done with that money? We spent about $14.5 billion in dividends paid and stock repurchase. We've used about $8.5 billion for debt reduction, and we've invested between $16.5 billion and $17 billion in projects and acquisitions at what we believe and what has proved out to be very attractive returns. So if you look at that, we have a stock value of just north of $40 billion. We've returned about 36% of that market value to shareholders since 2016 through the payment of dividends and the repurchase of shares. Now we know that our shareholders have a wide range of opportunities and investment alternatives. And how does energy infrastructure in general and Kinder Morgan significantly compared to those alternatives? And this Slide 7 sort of demonstrates that. If you look at some of the things that we think are important for an investor to look at, we think we score pretty well, and the whole energy infrastructure does. We have long line of tangible assets. We have customer contracts extending for several years. We believe we support a key part of the economy, not just in the United States but around the world as the demand for LNG in both Asia and Europe in the last year has certainly shown. But the last 2 checkmarks on this sheet, I think, are particularly important. There are high barriers to entry into our business. It's not just from the standpoint of having the capital to invest, but unfortunately, in my view, the regulatory hurdles are enormous today in investing in new facilities and energy infrastructure. Now that's a bad thing for the economy in general, I think, but it's good for a company like Kinder Morgan, where you have 80,000 miles of pipeline and all these other assets that are simply irreplaceable in today's regulatory permitting environment. And then finally, the last check mark, I think, is also beneficial for an investor who's looking at energy infrastructure and Kinder Morgan and that is a significant cash flow returned to investors through dividends, and I'll show you a slide on that in just a minute. Now I think increasingly, the market in these kind of volatile times is beginning to realize that assets that generate real cash flow will outperform more speculative investments. And this is just a snapshot of 1 year. But as you can see, where the Alerian Midstream index turned out compared to more speculative investments, and it's quite a difference in '22. This is a trend that we think will continue as we move forward and what I suspect will continue to be volatile times in the broader stock market. Now let me talk about dividends and returning value to shareholders. We believe that a dividend and the market has reinforced this view as part of the return provided to all investors. And in fact, if you look back over the last century, since we've been keeping statistics on this, the dividend has been an important part of the total return that investors get, whether they're investing in specific stocks or the S&P 500 or some other management -- some other general index. Over the last 10 years, in a bullish market, over 25% of the return in the S&P 500 has been from dividends. Now if you look at this Slide 8 or Slide 9, you can see today's energy segment of the S&P 500 is by far, the best dividend yield at a little over 4% better than any of the other segments, and we think this has real value on a going-forward basis. If you look at Kinder Morgan specifically on the chart on the right-hand part of the slide, as you can see, we're one of the top 10 dividend payers in terms of yield in the S&P 500. And this is not a flash in the pan situation. We've been paying dividends for 25 years and '23 marks the sixth consecutive year we've increased our dividend. And we expect to continue to be able to make modest increases in that dividend in the coming years beyond 2023. So to sum it up, why should Kinder Morgan be a core holding for any investor, whether energy-specific or a generalist investor? We think there are several significant advantages that we bring to the table. The first is we happen to be the largest energy infrastructure in the S&P 500, and we think size really does matter in terms of long-term outlook and in terms of long-term capability of delivering value to our shareholders. As I've said, we have a highly aligned management with significant equity interest in the company. We're able to continue to grow our EBITDA between '22 and '23 and coming off a very good '22, we're projecting another $200 million increase in EBITDA year-over-year. We have a nice dividend yield, and we raised it again this year by a modest 2%. And then we have a share buyback program, which our Board recently increased, so we now have $3 billion of buyback authority, of which about $2.1 billion remains untapped. So for all these reasons, we think Kinder Morgan brings a lot of positives to the table, and we look forward to telling you our story this morning. And with that, I'll turn it over to Steve.

All right. Thank you, Rich. And so continuing on the theme here. I'm going to talk about outlook, and that's the outlook for our sector and also the outlook specifically for our company. Kim is going to get into depth on all the business units. Every one of them talk about the commercial and operating and financial strategy there. And then David is going to give you our financial philosophy. He'll review our capital allocation principles. He'll repeat our capital allocation principles, talk about our key performance metrics and then take you through the 2023 budget, which takes all of this that we're talking about, how we're executing and how we're running our businesses and takes it down to a set of numbers for the year that we will be tracking and updating you on as we go. So that's what we're going to -- and then at the end, we'll have a Q&A session with our business unit presidents, who are all here as well as our key staff organization heads. You're going to have an opportunity to hear directly from them during the Q&A as well as at lunch. Okay. Everything starts with vision and mission and values, doing our business the right way. And this ties into the large overall theme here, which is that energy -- affordable and reliable energy is essential to human development, and it's going to be needed for a very long time to come, which means that our assets are going to be needed for a very long time to come. And one of the obvious truths about energy, but one that's not covered very much is that energy is absolutely essential to pulling people around the world out of poverty giving us all an opportunity at a meaningful life. The ability to get around a strong economy, the food we eat, the shelter, the clothing that we wear, et cetera, all require energy and hydrocarbon specifically. Something that is not often focused on, a little under 20% of hydrocarbons goes into the 4 main pillars of a modern society, cement, steel, fertilizer and plastics. The things that you need to build a modern society and that increasingly are going to be required around the world as developing countries continue to increase their GDP and increase the opportunities for their people. That human development aspect of the energy discussion has been largely excluded. Yes, it's true. We have to avoid warming the planet and cooking ourselves. But at the same time, we have to keep feeding ourselves. And that part has been missing from the debate. And a lot of the decisions about the energy that's going to be consumed tomorrow are going to be made outside of Western Europe and outside of the United States, and they're going to continue to need what we do, and we're going to continue to serve those markets with our tie-ins to export facilities. Energy transitions take a very long time and energy needs grow over time. And energy transitions don't happen by taking away things or removing things. They happen by adding things. We're burning just as much wood today as we ever have, for example. So we cannot ban, mandate, fine, tax or protest our way out of this. We have to discover and invent and that takes time. In the meantime, we will continue to deliver the energy that people need while we gradually pivot and transition for the energy uses of tomorrow and while doing so responsibly and being good at ESG, and I'll take you through all of those things. Here, I think, are the key takeaways. Our assets and services will be needed for a long time to come. Energy is essential to human development, as I said. And what we do today, the assets that we use today can be used as I'll illustrate for you, for the energy forms of tomorrow. So what we -- like renewable diesel and sustainable aviation fuel and have some specific examples around that. The other key takeaways are, think about what it is specifically that we do, and I will illustrate this for you. In our Natural Gas group, we're less about the commodity than we are about the transportation of it, a lot more about the transportation of it and the storage of it so that we can provide the deliverability when it's needed. That demand for what we specifically do and the value of what we specifically do, providing that deliverability is growing over time. And Kim will illustrate this for you on some of the experience we're having in our contract renewals. So as you see seasonal variation in gas demand and as you see increasing penetration from renewable intermittent resources and the rolling off or retiring of baseload resources, the call on what we do increases in value, including in states like California, where renewable penetration is strong. Also because it is difficult, as Rich said, to get new infrastructure sided, that means that the existing infrastructure becomes more valuable over time. The grid is tightening. And as it tightens, we're able to get more value for what we do, better rates and add term length on many of our key assets. The other thing that I want everybody to take away. I hope everybody takes away is we are in really good shape. Our balance sheet is at 4x well inside our long-term leverage metric. And that's important because that creates capacity for us to capture opportunities, further strengthen our balance sheet or repurchase shares. You have to take that into account. You can't look at our capacity as just being once our DCF and subtract the dividends and subtract the expansion capital. We also have worked very hard over the years to build that capability and the option value associated with the balance sheet, and it's at the highest level -- the best level that it's been since we consolidated the company into a single C-Corp. So with that capacity and the business prospects that Kim is going to talk about, you can see we're in really, really good shape right now. The other takeaway, I was talking with somebody about this earlier, it was in here and then it was out of here. It's not something we get asked about very often, but it is culture. We have a very strong culture. And that's illustrated in how we undertake succession planning. It's illustrated in how we all get on the same page from a strategy standpoint, how we deal with upsets, how we capture opportunities. It's embedded in our culture. We work extremely well together as a team, and we're all on the same page. And that is critically important to the success of the company. So now I'm going to go through some of the numbers that support the points that I just made. So what you have here, again, with the overall theme, energy is essential and hydrocarbons have enormous advantages. It's going to take a long time. We're going to continue to need more of them when we have a growing population around the world and a rising standard of living. And so the data that's shown here is 2022 EIA data and it's shown for 2021, 2030, 2040 and 2050. And you can see these things are all moving up and to the right. Over that period, the U.S. population is expected to grow 13%, GDP grows faster. Renewables double over the period but natural gas and oil product demand also grows and about in sync with population growth. And this is just the domestic picture, okay? This is just for the United States. We'll get into the global outlook for demand in just a moment. The other contributions from hydrocarbons are in the things that we use every day, as I mentioned, building materials, fertilizer, plastics, et cetera. And just to give you -- put some more context on this In just a couple of years in the current century, China used more cement than the United States did in the entire last century. When we built the interstate highway system, we built every airport, and we built most of the streets and buildings that we have today, okay? That's how much this stuff is needed to a growing economy. And there's not a substitute for hydrocarbons in making cement, steel, fertilizer and plastics. There's no economic substitute, but I'll say this. Once there is one, my guess is that stuff will be stored in the same terminals we have today, okay? All right. Next, energy transitions take time. A few examples here. Coal took 60 years to achieve a 50% global energy share, oil took 60 years to achieve 40%, natural gas 60 years to achieve 20%, nuclear took 80 years from discovery to widespread deployment. So this is the data on how long energy transitions take and therefore, how resilient our business and serving the energy needs of today really is. Let's talk for a moment about the miracle of nuclear energy. It was the last miracle we really had in energy. And so it wasn't discovered by electric utilities. It was theorized, there was a breakthrough in theoretical physics at the beginning of the last century. 45 years later, we had a bomb. Ten years after that, we had a first commercial nuclear reactor. And in the late '70s, we finally had widespread deployment. These things take a long time. And what nuclear took out of just power generation as a share was 15%. That's what it took away from hydrocarbons and that's just power. That's not transportation, that's not manufacturing, that's not anything else, which nuclear didn't touch. Again, these things take a long time. The stuff that we do is valuable and adds to global GDP and accommodates a growing population and gives a better standard of living. On the next page, we look at cost. And this is a key point. You can see the U.S. cost compare it to what's occurred in Europe. And again, the world needs affordable and reliable energy. Most of the growth that we're going to see in energy is going to happen in developing economies, and they're going to be focused on pulling people out of poverty. You can see what the European experiment in energy shows, what an accelerated transaction yields. By that, I mean trying to make do with the stuff we have today as opposed to making this transition when we really have the stuff invented, discovered, commercially deployed, et cetera, that's going to make a very meaningful difference. So what we need to do is a global society and as a species is find the technologies that are both carbon-free and cheaper than what's available today because if it's cheaper, let's be clear, India -- if it's not cheaper, India isn't going to buy it. It's a very tall order, and we're nowhere close to having that today. And so if we're going to be serious and truthful in examining what's required here, you recognize there's a dramatic need for additional R&D and accelerated commercialization. We're not going to protest and ban and tax our way out of this. We need discovery and invention and accelerated deployment. So let's talk about what we have today, natural gas. Next slide, please. It's cheap, and it's reliable. You see it's on the far left here versus on an equivalent per MMBtu basis, the other energy forms that are available. Nearly 187 million Americans rely on it, 5.5 million businesses. It's reliable. Less than 1% of natural gas customers experienced an outage over the course of the year, whereas there's an average of 1 outage per year per customer in electric distribution system. So just 1% of natural gas customers who experienced it. In the electric side, it happens once a year to the average customer. So it's safe, it's reliable, it's low cost, and it's indispensable, and the network that we have is irreplaceable. You could make a similar argument about refined products as well. We produce this stuff. We gather it, we transport it, we refine it and process it. We transport and distribute it again, and it shows up in the gas station cheaper per ounce than the water that you can buy in that same station. The infrastructure we have is extraordinarily advantaged. And we're going to need more of it, more natural gas. And so you see here, we needed increasing quantities around the world, 19 Bcf a day incremental needed by 2050. That's more than 40% of what we use today. If you take into account the declines we need something more like 25 Bcf a day, which is almost 60% more than what we do -- what we have today. And a lot of that's going to have to come from the United States. This is an enormous opportunity for us in the United States. And much of the growth in demand is coming from Southeast Asia, India and the rest of the world. So it is key, fundamental and true, but often overlooked that what we do is essential to developing economies around the world. U.S., shifting specifically to the U.S., we've got growth in natural gas production. We have declining production in other areas, and we have a lack of scale in other areas. So the U.S. will be an important contributor to this, and this is obviously very important to us as a U.S. midstream company. So we have nearly 100 years of reserves. We have the most competitive market. We have the best natural gas transportation and storage infrastructure on the planet and the world's energy buyers can come to our shores and be met by dozens of producers competing for their business, investor-funded liquefaction facilities and shipping available to meet their needs. So if our politics don't screw this up. We have a tremendous opportunity for the United States, resources, our infrastructure, U.S. manufacturing and labor. And I think this has been apparent to prior administrations that have license and approve additional LNG facilities. And hopefully, with events in the world, we're increasingly discovering it again. Okay. Staying on this slide now. This is, again, going to the U.S. role. There -- what's on here in the bar charts is blue. The blue is the U.S. natural gas source to meet the growing LNG demand. On the right, you see our reserve base, almost 90 years in natural gas, almost 91 years for U.S. oil. And at the bottom, you see the growth between 2021 and 2030 in U.S. exports, both of natural gas and of oil. But going back over here to the natural gas side, the 2 dotted lines, the 2 vertical dotted lines are looking at 2 different scenarios. One is 100 million tons per annum of new LNG capacity needed by 2035. The other is in a so-called delayed transition scenario, and it's more like 170 million tons per annum. And so because of the difficulties of energy transitions that I was talking about before, I know which one I would bet on. But in any case, what it drives is it's a significant need for U.S. natural gas demand, which will increase demand for our infrastructure. We serve 50% of that market today. We're well positioned as Kim will take you through to attach additional load to the network that we have today. So long-lived resources at attractive prices, and that's going to drive the growth in natural gas and oil experts, and that's going to drive the value of the infrastructure that we have. Okay. And here's a reason for hope, right? This is the U.S. experience showing energy production and also emissions. And here's the bottom line. Our economy grew by -- from between the period of 2007 and today, our economy grew by 45% while emissions in the power sector declined by 36%. So we can't let the perfect be the enemy of the good here. This is an extraordinary progress. And if you flip to the next page, we can make it happen elsewhere as well. So this is showing the opportunity for a reduction in CO2 emissions between now and 2050 of 26% to the extent we can use U.S. natural gas to displace coal, that's where that benefit is coming from primarily. U.S. natural gas to displace coal elsewhere in the world. We have plenty of it. We've got the infrastructure that's required to get it there. To the extent we can use it, we can accomplish a great deal for emissions reductions around the world. Now this is getting into the point made earlier about the importance of our assets and our deliverability specifically and the value of deliverability, separate and apart from the value of the commodity. And so there are two. On the left-hand side, you see during a couple of key events, how much energy storage capacity that we needed in order to meet in this case, extreme weather events, and it runs between 40 and 50 Bcf a day of natural gas equivalent in order to meet those swings. And we experienced something similar in Elliott. We had demand that hit 160 Bcf. We had total supply around 80 Bcf, and the rest had to be made up with storage. On the right-hand side is translating that into terawatt hours, a power equivalent, and you see 50 Bcf of natural gas is about 6.1 TWh. 1.5 TWh is the expected installed battery capacity by the time you get to 2050. The other disadvantage that battery storage has is it just simply doesn't last very long. And so if you have a significant weather event, you use it, it's gone. Typically, it's a 1- to 8-hour time period that it's going to get used over. And if the event continues, natural gas storage can continue as a solution, you don't have time, you don't have the flex to recharge the batteries. And so this is why natural gas storage is going to meet -- is going to be required in order to meet variability and demand and do so more cheaply for a longer period, a longer duration and more reliably than you can with battery technology, even if you fast forward to 2050. On the next page, this has taken it through to a couple of recent events. And this is, again, expressed in power demand and how natural gas was used to meet it. On the left-hand side, this is Winter Storm Elliott that we experienced just last month. On the right-hand side is a July heat wave. And you can see when temperatures plummeted during Elliott, look at the period between 12/23 and Christmas day, power demand increased by 25%, wind generation decreased by 37% and natural gas increased by 63%. Similar story during the July heat wave, wind dropped by 52% compared to the prior 6 days. Gas increased by 28%. And those 2 numbers at 52% on wind was about 176 gigawatts for the day. Gas was 191. So gas more than offset the decline. So the point of these last 2 slides is that not only the power sector needs natural gas, but they need what we do, providing deliverability, using storage and transportation, even more as renewables are added and more baseload power is retired. And further, as shown on the previous page, renewables plus batteries don't even come close to getting the job done even if you fast forward to 2050. So on these 3 comps, just talking about what we're doing today, this is at Kinder Morgan, what are the opportunities that we're taking advantage of in the energy transition and what we're doing to participate in the R&D that's going to be required. So first, we're providing on the left hand, providing our services in an environmentally responsible way. We've been reducing our methane emissions and methane intensity and reporting on our performance and our progress in our ESG reporting and our communications with the ESG investing community. The second column over, we're positioning ourselves for and participating in the gradual energy transition in a way that is very responsible for our investors. So we are participating in these markets today in RNG, in renewable diesel, renewable feedstocks, in backstopping renewable power in our gas business, and we're doing it at returns that are attractive for our investors. And that's a responsible way for us to participate in it. We're also using our CO2 expertise in carbon sequestration that we announced last week. Our first transaction in what we hope will be a growing opportunity for us as soon as the permitting process for sequestration sites can speed itself up. And then finally, R&D, these are a number of things that we're participating in because as I said before, massive R&D investment and really public R&D investment is going to be required to really invent, discover what we're going to need for the future. And in the meantime, what we do will be needed for a very long time. So a couple of specific examples of how in that second column, how we're participating in the transition said at the very beginning. What we do will be needed for a long time, but it's also the case that we're well positioned to handle the commodities of the future, whether that's CO2 sequestration or new energy commodities, and this is talking about the attractive potential for biofuels in the United States. We can handle these fuels, and we do today with the assets that we have, and we're making capital-efficient investments to modify and expand and accommodate our facilities in our Terminals group on the Lower River region, where we are handling an increasing amount of renewable feedstocks and have a couple of facilities that are close -- a couple of tanks that are close to completion for one of our large customers there. And we're also handling it in our refined products business on the West Coast with renewable diesel hubs that we're establishing in both Northern and Southern California. So this is how we can participate in the fuels -- one example of how we can participate in the fuels of the future. On this slide, we're showing what we're doing to responsibly pivot to the new energy world. We're showing our ongoing activities to reduce CO2 equivalent emissions that's here on the left-hand side. We've identified about 17 million metric tons. And the right-hand side is new projects that amount to just under 10 million tons. And again, we're doing this -- it's a gradual transition. We are gradually pivoting, and we're doing it in a way that's very responsible for our investors. We have to be good at ESG if you're going to be in the hydrocarbons business, and we are good at it. We're well ranked in it. Environmental, social and governance considerations have been central to us for a long time, whether that's corporate governance and structure. We're working with the communities where we have our assets. Most of our assets, a lot of our -- all of our pipeline assets are on other people's property we've had for a long time, had to be good about how we interact with the communities along the way and have to do the work to keep our employees, our contractors and members of the public and the environment safe. This is stuff we've been doing for a long time. We're reporting it and putting it in the formats that many of the ratings agencies want to see. These things matter. They're good metrics. They're important to our coworkers, our shareholders, our customers, our regulators. I'll make one quick point about this. As hard as we and other companies are working on this and as hard as the various agencies are working to get this right, the fact that we've started to seek, we have sought assurance around our ESG reporting from third parties. This stuff is still developing. And to elevate to the level of financial reporting is a mistake, given its current state of development. So that's something that we're obviously closely monitoring and taking an eye on. We're working hard on this. So are others. But to think that it's at the level of where financial reporting is, it's just -- we're just not quite there yet, and it's going to take some additional time. So finally, coming back to where we started, what we needed to move the fuels of today and the future, we are essential to a clean, reliable and affordable energy future. And again, we can do it for today's energy. We can do it for tomorrow's energy. And the value of what we do specifically, our deliverability is growing in value and our company is very, very strong. So we are well positioned. Our balance sheet is in great shape. We've got good opportunities in front of us. We're in a really strong position and a good moment right now. So with that, I'll turn it over to Kim to give you more of the hard facts.

Okay, strategy and execution. I'm going to begin where Steve left off. We are well positioned for 2023. If you look at adjusted EBITDA, we're going to generate $7.7 billion in adjusted EBITDA. That's about 2% growth from last year. Our debt-to-EBITDA is at 4x but that's the lowest year-end net debt that we've had since the entity consolidation when we put KMP and KMI together in 2014. We have a nice balance sheet capacity. We've got $3.6 billion of balance sheet capacity. Now let me say a couple of things about that. We are happy to preserve this flexibility. This money -- this capacity is not burning a hole in our pocket. But it is nice to have to the extent that we can do some opportunistic share repurchase or that we find more attractive projects in addition to what we already have in the backlog. But again, happy to preserve the flexibility. We'll just use this more on an opportunistic basis. Our backlog multiple, we've got $3.3 billion in our backlog at a 3.4x multiple. We'll go into that a little bit more later in the slides. And then shareholder returns, we expect to return $2.6 billion through dividends to shareholders in 2023. So we generate significant cash flow. We take that cash flow, we internally finance our growth projects, we pay our dividend and then we've got balance sheet capacity for opportunities that present themselves in terms of share repurchase or attractive projects. Starting -- moving to the bigger picture for a second. The U.S. production continues to recover from the pandemic. If you look at natural gas production on the left, we are well above pre-pandemic levels. The natural gas production has been just amazing. WoodMac is projecting -- if you look at the Wood Mac, what they project for 2023 versus 3 years ago, the actual, we are up 10 Bcf a day. And we expect continued growth, which we'll go through a little bit later in the presentation. So just amazing story on natural gas. On crude production, it continues to recover from the pandemic. And during 2023, we expect that we will hit pre-pandemic levels. On the refined products side, those have recovered, but the recovery has flattened a bit, and we'll talk about some of our assumptions in 2023 around those volumes. Now drilling down on natural gas demand. I told you it's increased by 10 Bcf a day over the last few years. If you look over the last 7 years, it's grown by 28 Bcf a day. That's a 36% increase in natural gas demand. And if you look at the volumes on our system, the volumes on our system have increased by a similar amount. They're up about 35% going from 30.8 to 41.5 Bcf a day. Now for sure, we have added capacity during this time frame. But if you look at many of our long-haul systems, they are very highly utilized. And what you see on peak days is that we have constraints. And just to give you a couple of examples of that, on TGP, if you look at our utilization in 2015, it was at 86%. You look at it in 2022, it's at 97%. That's on average. If you look at P&G, it was at 67% in 2015, and now it's at 86%. And so it is difficult in this day and age now to build incremental capacity. And so as a result, what we're seeing with this high utilization is favorable recontracting. So we are -- where we can under the regulatory regime, we're able to increase rates. We are able to -- and reduce recontracting risk. We're able to push out our terms on our contracts. And so for example, if you look at the average term on our Texas Intrastates, we've gone from 3.5 years to 5.7 years since 2015. So plus 2.2 years in contract term. And so as a result of this, what you're seeing is that we don't have the same recontracting risk going forward as we've had in the past because these systems are filling up. The other thing is, as the system fills up, this leads to some expansion opportunities in the places where you can still expand. And that's primarily in the Gulf Coast, but that's also primarily where the demand growth will come. Now on the storage side, you look at storage capacity hasn't increased. It's only increased 1% over this time frame. The Kinder Morgan storage positions increased by about 3%. Now we're taking out acquisitions and divestitures, just to show you what's really happening to the actual storage capacity. Previously, and Steve went through some of this, the demand volatility has been historically driven by weather. But with the addition of renewables, you're seeing increased volatility. You saw that on the slide that Steve showed, where natural gas had to ramp so much during a winter storm because demand goes up in a lot of times during these weather events, the renewable capacity comes off. And so we -- he gave you the example during Elliott. Peak 1-day demand during Elliott was 162 Bcf. On that same day, supply, which is normally around 100 Bcf a day, dropped down to 86 Bcf because of well freeze-offs. So that meant that 76 Bcf had to come out of storage to meet demand. And as a result, that means we have been able to also increase rates and increase term on our storage portfolio. And right now, in terms of a greenfield, brand-new greenfield storage facility, building one of those, our rates today are still below what would be necessary to undertake something like that. So there's still an increment there before we think new storage capacity or significant new storage capacity gets built. Now on the products and terminals assets, they don't have the same underlying market growth but they are highly utilized assets and they'll be needed for a long, long time to come. Both products and terminals have a significant amount of their revenue that has inflation escalators. And so if you look at the products, 2/3 of our products segment EBDA has annual inflation-linked tariffs. That's largely as a result of the FERC tariff inflation escalator. That inflation escalator in July of this year was 8.7% -- or July of '22 was 8.7%. In July of '23, right now, the projections are that, that could be over 13%. Likewise, on the terminal side, 75% of our segment EBDA has annual price escalators. So you have nice increases in revenues built in through those inflation escalators to the extent that we can hold our costs below those, which we have been successful in doing in the past. Now on the volume side, products volumes in our budget, and David will go through this, we're expecting about a 3% increase in volume. Now that is -- that's very little growth in gasoline demand. Where we're projecting the growth is really in diesel associated with our renewable diesel projects coming online and then in jet fuel as a result of international demand coming back. On the Terminals segment, volumes don't have as much impact. And that's because this -- in this business segment, 70% of our contracts are -- revenue comes from take-or-pay contracts. So what that means, it's like when you rent an apartment. You rent an apartment and you don't stay there, you pay for it anyway. So on our tanks, you pay for it once you contract for those, you pay for them, whether you use it or not. So in the short term, we don't care about the volume that moves through those terminal facilities. Now in the long term, we want them to be highly utilized so that we can renew those contracts. And if you look at our historical utilization or capacity leased, we've run in the 90% and in 2023, expect to run around 94%. Moving to our strategy. So in the last 25 now, almost 26 years, our strategy really hasn't changed much. But we do respond to changing circumstances. And so the primary change has been in the second column here to invest in a low-carbon future. And so we established the Energy Transition Ventures group in 2021. In a minute, I'm going to talk about all their accomplishments. In our $3.3 billion backlog, 82% of that backlog is associated with lower carbon investments. And those are things like natural gas, renewable natural gas, biofuels and carbon capture. Now we still focus on owning stable fee-based assets that are core to the energy infrastructure. And obtaining multiyear contracts, we're focused on maintaining financial flexibility. So as I mentioned earlier, we project to end 2023 at about 4x debt-to-EBITDA versus our long-term target of about 4.5x. And we have ample liquidity. We've got a $4 billion revolver. We're very disciplined in the way that we allocate our capital. So we target returns that are well in excess of our cost of capital. If you think on average, we target around 15%. Some projects are a little bit less than that, where we have long-term take-or-pay contracts with good credit quality customers. Projects that have more variability in the revenue stream that we may target a little bit higher than that, but in and around 15%. And when we model those, we use conservative assumptions. And so when the contracts roll off, we're generally assuming that there's some degradation in rate. And we try to be conservative on the terminal values that we use in those models. The other piece of the disciplined capital allocation is on the balance sheet. We have reduced debt by $11 billion since the first quarter of 2015. And so that has put this company in a very strong position. And the final prong in our strategy is really focusing on enhancing the shareholder value. We do that through the 4 things we've mentioned in the columns preceding this one, but also returning cash to our shareholders. And so we returned substantial cash to our shareholders through the dividend, and we target to grow that dividend a little bit every year and generally in line with the base business. And then to the extent that we have money above that, and we opportunistically do some share repurchase, and we did $368 million of that in 2022. So in '22, we executed pretty well on the strategy. We generated $7.5 billion of adjusted EBITDA. That was a 10% increase over 2021, which is fantastic in a stable fee-based business like we have, and we were up about 5% versus our budget. We ended the year at 4.1x debt-to-EBITDA versus our target of 4.5x. We returned $2.9 billion of money to shareholders through the dividend and the share repurchase. We brought $400 million of projects online, and then we added $2.4 billion to the backlog. And I'll take you through some of these projects in a minute. But just seeing a lot of opportunity out there. We acquired some 2 RNG businesses for a little under $500 million. And then we sold an equity interest in our Elba JV. And so people say, well, why are you selling assets? And the answer is, we're economic creatures. And so if we can sell an asset at a high multiple and reinvest that capital at a much lower multiple then that is a value-generating transaction for our customers. So we sold Elba at about 13x. If you look at the multiple on our backlog, it's less than 4x. If you look where our shares trade today, it's less than 10x. And so we can take that money and reinvest in more attractive opportunities. And so where we find those opportunities, we don't find them often, but when we find them, we are happy to pursue them. One of the pillars of our strategy is owning stable fee-based assets. And part of that stability comes from the contract structure. So if you look at contract structure, 61% of our adjusted EBITDA comes from take-or-pay contracts. When you think about the price volume equation and revenues, that means price is fixed and volume is fixed. We talked about that on the Terminals assets. You rent the apartment, you rent the tank, you pay, whether you use it or not. So highly stable, 61% of our business. 26% of our business is fee-based. So what that means is price is fixed, volume is generally -- is not fixed. But on the volume side, the assets that make up this 26%, we generally operate in a pretty tight band. And so let me tell you, excluding the pandemic, I think if you look at the extremes, that's probably plus or minus 10%. When you see those extremes, those extremes would be things like tremendous increase in commodity prices or tremendous decrease in commodity prices or a very deep recession. Let me give you an example of that. So -- and again, all this is excluding a worldwide pandemic. But in 2007 -- in 2008, when you look at our products pipeline volumes compared to 2007, they were down about 7%, okay? And that is a pretty deep recession. We probably budgeted 1% or 2% -- a couple of percent growth. And so those volumes were down a little under 10% versus our budget in an extreme event. If you look at the past 5 years on our G&P volumes, versus our budget and you exclude 2020, the pandemic here, we are then about 4% of our budget. So much more closer to our budget versus 10% that you might see at the extremes. Then on hedged 6% of our segment EBITDA is hedged. What that means, it's just like the fee base. Price is fixed, volume is -- may not be fixed or generally is not. And so here on the volume variability, this is primarily associated with our CO2 operations. And there, when you look at us versus our budget, we're largely able to call our shots. We have been within 1% of budget over the last 9 years on that business. And so not a lot of volume volatility here either. And then 7% of our business is we're exposed on price and on volumes. And our sensitivity here, the primary sensitivity we have is to crude oil volumes, and that sensitivity, as David will take you through, is $5.8 million in EBITDA per $1 move in -- $1 per barrel move in the price of crude. So also contributing to the stability of our cash flow is our customers' need for the products that we transport in store. They need these to run their business. So 71% of our customers are end users. So for example, they're LDCs that need the gas to serve their customers. Their industrials, a cement plant or a plastic plant that need the gas in order to run their business. So 71% need us to run their business. 76% of our customers are investment-grade credit rated or have substantial credit support -- post substantial credit support. So if you look at the customers that are B- or below rated, that's -- and you consider what we could remarket capacity for and the collateral that they posted, less than 1% of our net revenue is exposed to customers that are B- related, after you take those 2 things into account. So very strong customer profiles. Now part of delivering value to our shareholders is originated projects with returns that are significantly in excess of our cost of capital, and delivering those on time and on budget. And so on this slide, we're looking back. So looking back over the past 3 years, 2021 and '22, at the projects that we have brought online, we've spent $2.2 billion. We estimated when we entered into the contracts to do these projects that we would have a first year or year 2 EBITDA multiple -- achieve an EBITDA multiple of 5.1x. We had some cost savings on those projects. And so what we actually achieved was better. We achieved 4.6x. Now a big portion of the $2.2 billion in projects we brought online were in natural gas. And you see a similar story here. 5.3x was our original estimate, and then primarily due to cost savings, that came on at 4.5x. Now these multiples, we're going to -- on the next page, we're going to go to our project backlog. You're going to see there, we have a 3.4x average multiple on the backlog. These multiples are a little higher than that. And let me say, we target certain returns. And those returns, as I said, around 15% unlevered after-tax returns, those returns are well in excess of our cost of capital. So that doesn't mean that we expect forever and ever to be able to do projects at 3.4x or 4.6x. We are willing to do projects that may be at a little bit higher multiples than this. Again, as long as they meet our return criteria of 15% or better, again, sometimes a little lower, sometimes a little higher, just depending on the stability of the cash flow, as long as they meet our return criteria substantially in excess of our cost of capital. But here, the multiples are a little bit higher than the backlog, and that's because there's some greenfield projects that we brought online, which tend to have a lower multiple than when we're building directly off of our existing network. So PHP is in this group of projects. We had a terminals project for a very large customer that was going to leave us. Again, the returns we earned on it were well in excess of our cost of capital, but we were able keep that customer. And -- but that was at a little bit higher multiple than the 3.4x in the backlog. So again, we're targeting returns, those returns in the future may result in higher, maybe lower multiples, but again, always significantly below our cost of capital. So looking forward on the $3.3 billion capital backlog, we ended 2021 with roughly $1.3 billion in backlog. So during 2022, we originated new projects of $2.4 billion. So a really good year in terms of finding new opportunities. And we put about $400 million of projects in service. So we added roughly $2 billion to the backlog on a net basis to go from $1.3 billion to $3.3 billion. And as I said a minute ago, those projects, the EBITDA multiple on the projects, excluding CO2, about 3.4x, and 82% of those projects are lower carbon projects. As we look forward, historically, 3-plus years ago, we used to say we expect to spend $2 billion to $3 billion annually, and we've said this on a number of calls. Right now, our estimated pace is more like $1 billion to $2 billion. And we're spending a little bit over that in 2023, as David will show you. Now many have asked what are the projects that make up this backlog. And so this go through some of the major projects that make up the backlog. The biggest project in our backlog is the TGP and SNG pipeline project to serve Venture Global. And so it's a 2 Bcf of capacity, moving on a combination of SNG and TGP. We've got 20-year contracts, and the project will come online in '24 and '25. The second biggest project is $283 million project. This is a debottlenecking project within our Texas Intrastates that will come in service late this year. KinderHawk, the Haynesville, as I'll show you in a minute, has tremendous production growth. Given all the demand for LNG exports, it was just born in the right place. And so we've got a lot of opportunity there on our gathering assets. The TGP East 300 expansion, that's a pipeline expansion to bring incremental gas into New York. It's a compression expansion. Compression expansions tend to be highly economic. We've got 20-year contracts there. That comes in November 1 as our projected date on that. So those are some of the natural gas projects on products. It's really the renewable diesel project. So $73 million of renewable diesel projects. We'll go through in a minute. In terminals, we have the feedstock, the renewable diesel feedstock hubs for REG/Chevron and for NESTE. And then we've got a conversion project, which lowers greenhouse gas emissions in Pasadena by 38% for $64 million. And then we've got the ETV projects of about $300 million, converting some of the gas coming off the landfills to be pipeline quality. And that gets you to about 84% of the backlog. So these are the biggest projects in the backlog. Okay. Now before we go through the individual segments and break down the relative contributions for you, natural gas pipelines, about 62% of our segment EBITDA. Rich said that the other 3 are kind of roughly equivalent. And you can see that here, 15% on products, 12% on terminals and 11% on CO2. Now if you broke this down based on the commodity type, you say 62% is gas. You have about 20% of our business, those refined products when you combine what's in the product segment and the Terminal segment. You've got 10% that is CO2 related, and then you've got 8% that is either crude, bulk terminals or energy transition ventures. And so what I call other. So that gives you a sense for how the business mix breaks down. And so we'll start with natural gas, where we own the largest gas transmission network with about 70,000 miles of pipe. We transport about 40% of the natural gas that moves in this country, and our storage position is about 15% of the U.S. market. We've got about 700 Bcf a day -- 700 Bcf of storage. Now looking at what's expected to happen on the supply basins and natural gas. WoodMac is showing about 20 Bcf a day growth in supply between 2022 and 2030. And so where is that growth coming from? And it's really coming from 3 primary basins. Now the biggest piece is the Permian expected to grow by 10 Bcf per day. We have, once we get the PHP expansion online, which will happen later this year, we've got over 8 Bcf a day of export capacity out of the Permian. Almost 5 of that really moves through the Gulf Coast, and then the rest moves to the West and Mid-Continent through EPNG and NGPL. The second largest growth in terms of just Bcf per day is coming from the Haynesville. And so there, as I showed you in our project backlog, we have a lot of opportunities to deploy capital associated with this 8 Bcf a day of growth. And then the Northeast is about 5 Bcf a day. And our TGP pipeline runs through the Marcellus/Utica. And it's kind of bifurcated. It takes gas into the Northeast to meet demand there. And then into the Gulf Coast, primarily to meet LNG demand in the Gulf Coast. So really nice picture on the supply side, and we are able to access the basins that have the most significant growth. Now on the storage side, as we've said, we've got the largest storage position. As Steve talked about, and I've talked about, storage is really the key to supporting the variability in natural gas demand that has increased from just being weather-driven to being also driven by renewable load, which decreases a lot of times during -- well, when the sun quit shining or the wind quits blowing, and that happens many times during storms. And then the variability with LNG demand. Right now, Freeport back online. You probably -- there's about 14 Bcf a day of LNG export demand once you get that facility back online. And so if the market fundamentals are changed, then people may not be pulling that gas away. And so then it's got to stay and you've got to find a place for a lot of gas. And so storage is the key to balancing that volatility. The other -- we have some ability to balance through the pipeline services that we offer, not just the storage facilities. And -- but the nonratable services that we offer, whether that's on the pipeline side or that's on the storage side, they get priced at a premium, right, because it's harder to manage that demand. And so our no-notice service, our pressure guarantee service, all those things get priced at a higher margin than what our base load demand gets priced. So we've talked about supply. On the demand side, WoodMac projects demand growth that largely is in line with the supply growth. 95% of the demand growth is expected to occur in Texas and Louisiana. And if you look at the map on the right, I mean our system is very well positioned to serve that. LNG demand between 2022 and 2030 is expected to more than double. Demand to Mexico is expected to grow by 3 Bcf a day. Industrial demand is expected to grow by 3 Bcf a day. And then power demand is actually expected to decline by about 3 Bcf a day. On the next slide, I'll talk about the LNG and our position and ability to serve that. But on the exports to Mexico and the industrial demand, that 6 Bcf a day of growth. If we really see more deglobalization, I would say there's probably upside in those numbers. If you really see a lot of industry coming to the U.S. and moving out of China and other places across the world. Now on the power side, they may need less base service from us. But as Steve has showed you, they're going to need more nonratable services, which are premium services. So there's ability to offset that decline in demand. All right. Now looking at LNG. Today, we're contracted to move about 7 Bcf a day of LNG, and we're around 50 -- roughly 50% of the market. We've got another 3 Bcf a day that is -- we have signed contracts for and that the facilities will come online, we're projecting in 2025. And so at that point in time, we'll have 10 Bcf a day of contracted LNG capacity. Now the market and this is a WoodMac projection is expected to grow to 26 Bcf a day. And so given our asset position in and around the Gulf Coast, there should be opportunities for us to serve this. And many of them we can do in a very capital-efficient manner. But we are going to maintain our financial discipline. And so if someone else is willing to build a pipeline on spec or willing to do it at a very low cost of capital, we're not going to compete with that. But given the pipeline network that we have, we should be able to provide cheaper alternatives where we can build off our existing system than new build capacity in many cases. So we're in a very good position on the LNG -- for the LNG growth. Now on the product segment, we're the largest independent transporter of refined products. Pipes are the cheapest and safest way to move refined products. We've got about 9,500 miles of pipe, primarily, as you can see on the map, in the West and in the Southeast. We move about 2.2 million barrels per day. Now that breaks down roughly 3/4 of that volume is refined products, with the biggest piece of the refined products being gasoline. Gasoline is about 60% of the refined product volume. And then we've got about 25% that are crude volumes and kind of equally split between the Bakken and the Eagle Ford. And tank capacity in our products group, we've got 56 million barrels of tankage capacity. So refined products has been a very steady contributor for our business. If you look at the volumes since 2015, the volumes are relatively flat, up 0.1%. Now that's better than the market overall. If you look at the market, it's slightly down. So we're a little bit better than the market. Now the other piece of the -- on the price side of the equation, we are able to -- we have the inflation adjusters we talked about. And so as a result, even though we haven't had a lot of volume growth, our adjusted segment EBITDA has grown by 3.2%, and expansion projects have also contributed some to that, but we're doing better than what you see the volume growth. And so what happens on the inflation escalator is these are high fixed cost, low variable cost business. And so if you can get 2% or 3% or right now a lot greater growth on the top line, and you can manage our costs appropriately, then you get that operating leverage, and you can have a little bit better growth on the bottom line. On the refined products side, we're also seeing opportunities on the renewable diesel, which I'll take you through on the next slide. And then we found opportunities on the blending side, so blending naphtha or blending butane. So on the renewable diesel projects, we've got about $73 million all on the West Coast. The demand for renewable diesel is really driven by the federal and state subsidies, which encourage the use of biofuels. The subsidies are most significant in California. So in California, right now, these subsidies are about $4 per gallon. Most of these projects that we have, we've got some in Southern California, some in Northern California, and they are expected to come online in the first quarter of 2023. And this is part of what's really -- or this is a lot of what's driving the diesel growth -- diesel volume growth in our products pipelines in 2023. Now moving to the Terminal segment. We're the largest independent terminal network. If you take the terminals that are in products and you combine them with the liquids terminals that are in the terminal segment, we've got 134 million barrels of liquids capacity. So very significant position. Within the Terminal segment, if you just look at the liquids piece, so the liquids, and we include the Jones Act in that, that's about 75% of the segment. And then 25% is really the bulk business, where we are storing and moving for customers, pet-coke, steel and coal are the 3 largest products. So -- and as you can see, our terminals are spread across the coast and through the inland waterways across the United States. Now not all liquids terminals are created equal. Some are just pots and pans and buckets. But John and his team have worked really hard to create hubs, which have tremendous connectivity and liquidity for our customers. And Houston is the prime example of this. It is our largest liquids terminal within the Terminals segment. It constitutes a little over 50% of the liquids capacity. So we've got 43 million barrels of capacity in the Houston Ship Channel. You've got 31 inbound pipes. And -- so we're connected to 10 refiners, and that's 2.5 million barrels of output at a -- refined product output a day that comes out of those refiners. We're connected to 8 chemical facilities. We're connected to Mont Belvieu. And so you have a lot of products coming in, primarily refined products but also chemicals, and then some products that are used -- that our customers use for blending. We've got 18 outbound pipelines. And so the 2 biggest, Colonial, which moved product into the Southeast and into the Northeast; Explorer, which goes in the Midwest to Chicago. We've got cross-channel lines, which connect our terminals. And so we can freely move products between Pasadena and Galena Park. Our customers can go outbound on the pipes, they can go outbound on the ships or barges. We've got 11 ship docks. We've got 39 barge spots, and then they can also go over the track rack into the retail market in and around to Houston. So we've got 35 truck bays. And then we also have unit train facilities which bring in primarily ethanol, but we also have the ability to take refined products outbound. So a lot of people can build tanks, but replicating this group of assets and the connectivity that we have in this is really near impossible. So Jones Act market, really good underlying fundamentals right now on our Jones Act tankers. We've got 16 tankers. They're about 8.8 years old. And the industry dynamics have tightened significantly, and that's for a couple of reasons. One, the Russia-Ukraine crisis; two, moving RD from the Gulf Coast to the West Coast, where it's most profitable to sell; and three, there's some statutory limitations, new statutory limitations on issuing waivers. So rates have increased significantly. If you look at rates, they've improved from $58,000 a day at the end of '21, and spot rates right now are about $75,000 a day. Now that's a spot rate. Long-term contracts may be a little bit less than that. But that gives you a sense for the increase in the market. And if you look at how that market compares to what it would take to build new ships and bring new supply, tanker supply onto the market, those rates, it would have to be $100,000 a day. So you have a fair amount of room between where we are and where new supply would be brought on. And we have also -- we not only increased the rates, but we've also increased the term. So the term has increased from -- of our contracts has increased from 1.3 years in 2022, now to 3.3 years today. And that doesn't include likely options, where our customers have options to extend those contracts and the rates are such versus the market that they would probably do that. So if you included likely options, the term would be a little bit longer. And when you look at our charter profile, we've got 93% of 2023 is under firm charter, 93% of our capacity is under firm charter. You compare that where we were last year at this time, we were at 19%. So just a dramatic change in the market. And if you look at the likely options that will be exercised in 2023, we're at 100%. If you look at '24, we were at 25% last year at this time. Now we're at 79% and likely over 90% if you include the likely option. So just really nice change in the underlying fundamentals on the Jones Act, and that's driving some nice EBITDA growth in our Terminals segment. Another place where we're seeing growth on the Terminal segment is on RD feedstock, renewable diesel feedstock project. So we've got 2 feedstock projects, both in the Lower Mississippi, one for NESTE and one for REG, now Chevron. So it's $134 million of total investment. It's about 900,000 barrels of storage. The NESTE project is almost complete. It will be complete during this quarter. The REG project will complete at the end of 2024. There, we're really just starting that project. And this -- on the NESTE project, in particular, one thing that we're seeing is this is new business coming into this terminal. And so as a result of that, occupancy in that terminal is going from what has historically been 70% to 80%, and it's going to go close to 100%. And then the other thing, as a result of that, we're seeing, is the ability to increase rates. So you can see a similar story here where, as demand increases, as you bring in new business, the market expands, our assets are filling up, and that allows us to increase rates and/or term. All right. Turning to CO2. So in the CO2 segment, we've got 5 oil fields in the Permian Basin, most Texas. And really, it's 2 fields, Yates and SACROC, that are the most significant fields, and they account for over 90% of our net oil production. Then we have interest in 3 CO2 fields, 2 of them in Southwest Colorado, and we have pipelines that connect those CO2 source fields to the oilfield. And so what we're doing is we're bringing CO2 down and injecting it into the oil fields in order to produce oil, and CO2 is used in tertiary oil recovery. Right now, we're moving a little over 900 million cubic feet a day of CO2 down the quartiles pipeline primarily. And -- but it's got capacity of -- we've got capacity of 1.5 Bcf. So room to grow if needed. We take that CO2 that we're moving. We sell a portion of that to third parties, and then a portion we used to flood our fields, and we produce about 30,000 barrels a day of oil net to Kinder Morgan. Now this business generates very consistent cash flow for us. If you look at the operating cost versus the cash operating cost versus the prices we achieve, if you look at the 2 most recent years, cash costs are about $25 a barrel. And we're getting $64 to $67 a barrel. So horseshoes and hand grenades, $40 a barrel of margin. And that margin provides a return on our capital. And so if you look at the chart on the right-hand side of the page, we have generated free cash flow after expansion CapEx of -- between $350 million and $560 million. These are the investments that we are undertaking today in these businesses at SACROC and Yates. Those fields are very developed in terms of the infrastructure that you need. And so generally, the projects are about drilling incremental wells, and as a result, highly efficient capital projects and nice returns. Almost all the investment, as I said, is at SACROC and Yates. And if you look at the 20 projects that we have approved right now that the CO2 group is pursuing, 17 of those projects have an IRR greater than 30%, okay? And then 3 have returns that are in the high teens and into the mid-20s. So you can see what I mean when I say these are very nice returns on these projects. All right. Turning to Energy Transition Ventures. As I said, we set up this group in 2021 to look at opportunities really outside of our existing asset base. And -- but these opportunities have to fit our strategy and our return criteria. So the first thing the team did was they went in and started sifting through all the opportunities to find opportunities that they thought matched our strategy and they put them into 3 buckets. And so the most actionable bucket was really the first one, which is renewable natural gas, renewable power. The second opportunity, which is the medium-term bucket is what I would call it, is really the carbon, the CCUS, or CCS, carbon capture and sequestration. And then the long-term bucket is hydrogen. And so on the hydrogen, it's really -- at this point, it's really more about R&D. Can our storage facilities hold hydrogen? Can we transport the hydrogen in our pipes from -- without causing any integrity -- any integrity issues? So to date, the ETV, that we've executed on 3 acquisitions, all in RNG, about $800 million of capital spent to buy those, and 1 CCS project that will go over at Red Cedar that Rich mentioned in his presentation. So looking first at the RNG market opportunities, you can see this market is expected to grow dramatically. Now it never gets huge, but nice growth, and it gets to a decent size. And this is really about capturing natural gas coming off landfills, coming off of dairy farms and moving those, cleaning up that gas, moving it in pipelines. And then there's 2 different markets today that you can sell that gas into. One is the transportation market. And when you sell it into the transportation market, the renewable natural gas vehicles generate about 75% less GHG emissions than diesel vehicles because it's primarily -- these molecules are primarily going in to commercial vehicles. Now the -- they typically pay Henry Hub or NYMEX price for this gas. But when you sell this gas, you also get a RIN, which -- and so the value of the RINs today is like $26 -- over $26 an MMBtu. And so on a combined basis, you're getting $30 roughly of value when you put product into the transportation market. Now the other market that you can take these volumes is a voluntary market, and that's where people are interested in decarbonizing, like a utility wants to decarbonize and have some decarbonization goals. When you take it into that market, it's a slimmer margin, so a lower price. But there, you get a fixed price, so you don't have the variability that you have with RINs, and you can get long-term contracts. So more stable business. So you have more stable business but less upside, a little bit more on -- on the transportation, you've got more volatility, but a whole lot more upside. So we target to have a portfolio that is mixed between the transportation market and the voluntary market. Now a new market that has recently come out, the EPA just issued their renewable volume obligations for the next 3 years. And in that, they included eRINs. And so this is when you're using RNG to basically -- into the power market in order to use to charge the electric cars, okay? You get an eRINs. And so that is a market that we're currently exploring. The regs aren't finalized yet. We expect that will be finalized in June, but it's something that we're exploring. So when you look at our -- on the next slide, if you look at our portfolio of acquisitions, we've done 3 total. In those 3 acquisitions, we've got 6 potential conversions. 4 of those conversions are under construction today, 2 are not yet under construction. Now if we do all RNG pipeline quality gas, we will get up to 7 Bcf per year of gas off these facilities. It will cost an incremental $300 million to convert all of those. And -- so we'll have a total investment of about $1.1 billion, and we expect to bring those projects on at less than a 6x multiple. Now having said that, on the 2 projects that are not currently under construction, as I said, we're looking at the eRINs market. And so there, we will evaluate the 2 sites that are not under construction for eRINs. And on the eRIN side, there, if we pursue that, it would be less capital on those sites, but we still get incremental cash flow associated with the RINs that you would get. So it's a nice way to reduce emissions. You can see that the 7.4 Bcf a day of RNG reduces emissions by 4.2 metric tons (sic) [ 4.2 million metric tons ] of CO2 per year. Turning to CCUS. So in this, there's multiple steps in the chain in order to capture and sequester CO2. So you have your emission sources. You've got to go capture the CO2 off those emission sources. You've got to transport it to a well where you can inject it and sequester it. So I think we are able to play in all 3. Well, typically, we're going to be on the capture transport and sequestration side. More of our expertise is on the transport and sequestration side, building the pipe. And then because of our CO2 business, we know how to inject that gas. We know how to look at the geology to make sure that we can contain that gas in the reservoir. And this CCS is economic because of the tax credits that you can get, the 45G tax credits, which increased last year. And so prior to the increase, it was really -- there were very few types of facilities. Natural gas processing facilities and ethanol facilities were really the only ones that you could economically do carbon capture. Now more facilities have become economic. And so you have some natural gas facilities where it might be economic. You have some coal facilities. You have some ammonia facilities where these projects can be economic. Really, the biggest gating item today on these projects is about the sequestration. And so you need -- in order to sequester, for the most part, you need a Class 6 well permit from the EPA. And there have been a lot of permits filed with the EPA, but there haven't been any permits issued recently. Texas and Louisiana have both filed for primacy, meaning they would take over this permit process from the EPA. Louisiana is much farther along. Texas just filed theirs. But I think if some of the states get primacy, that could help speed up. But on our next slide, the specific project that we have on Red Cedar, we are -- it's less -- as Rich said, it's relatively small. It's less than $50 million of CapEx. We're involved in all 3 pieces of it, the capture, the transport and the sequestration. So we have a joint venture with Red Cedar where we emit the CO2, primarily from a trading facility. And so Red Cedar is going to build the capture technology, and then they're going to build a small pipeline down to Cortez pipeline, which is our long -- our pipeline which goes from Southwest Colorado to the Permian Basin. And then energy transition and CO2 group will take it, the CO2 down into the Permian Basin, where we will inject the oil into an existing wellbore and think that we may be able to use a different type of permit to do that, but we would need the Class 6 permit. And so therefore, could get this project done more quickly, we think, by the second quarter of 2024. Now in terms of volume, we're talking 10% to 20% a day. And so where this market is today, I think, is there are opportunities for smaller projects. And really to do the larger projects, we really need to see Class 6 permits issued from the EPA or from the states if they get primacy. So as Rich started off, we think this is a compelling investment opportunity. We're the largest energy infrastructure company in the S&P 500. We have very stable cash flows. We've got a strong balance sheet that has a lot of flexibility. We've got a nice backlog of projects with attractive returns. We've got a 6% dividend yield and -- which is, as Rich said, top 10 dividend yield in the S&P 500. We've got the flexibility to do some opportunistic share repurchase. And we've got a highly aligned management team that has 13% share ownership. So with that, I think we're going to take a break. Or we're going to go to David. Okay.

Just one more before the break. So hang in there. So I'll begin with our capital allocation priorities. And for those of you who followed us, who know us, this isn't going to be a surprise. These don't change for us. And it all begins with a strong balance sheet. We think it's important to have leverage as part of our overall funding mix because it reduces the more relatively costly form of equity funding, but we know that we have to have that in a -- we have to have that leverage in an amount that is appropriate for us given our credit profile and overall business mix. As for allocating capital to our growth capital projects, we target a 15% unlevered after-tax rate of return. It does -- that rate of return does vary somewhat with regard to the special project risk profile. But the process that we follow internally is very consistent, it's very established and well-known across our business, across our business units. I skipped over or maintain our dividend. We have a bias towards paying out significant amount of cash flow to our shareholders. We think that our business mix enables us to do that in a modestly growing manner, but in a very significant overall cash flow size. And then finally, should we have excess cash in addition to funding our -- left over after funding our dividend and our growth capital program, we look at 3 different ways of returning additional or creating additional value for our shareholders, retaining some of that cash flow on our balance sheet, using it for unbudgeted capital projects and acquisitions and potentially using it for share repurchases on an opportunistic basis. Moving on to the next slide. What does that look like for 2023? So in 2023, we expect to generate $5.7 billion of cash flow from operations. We expect to spend $2.8 billion of that on capital. And that $2.8 billion includes our sustaining capital as this is a GAAP metric. We expect to spend $2.5 billion in dividends for the year, and we expect to have $2.6 billion (sic) [ $3.6 billion ] of balance sheet capacity. And as Kim mentioned, this is capacity that's created when you take our long-term leverage target of around 4.5x compared to where we expect to end the year at 4.0x, apply that to our EBITDA projection, and you get to about $3.6 billion. So a lot of capacity for each 0.1x turn of leverage capacity that we could utilize that represents about $770 million or 2% of our market cap. So a lot of flexibility there. When you combine that with our free cash flow that we expect to generate in the year, that brings you to about $4 billion of total available capacity for the year. So one note here is we want to make sure that we -- it's very clear. We're going to take a very disciplined approach to utilizing this capacity. We recognize that reducing leverage on a balance sheet is a difficult task, and we've been doing it for a while, and we recognize how hard that is. So we don't want to utilize this capacity lightly. We'll take our usual disciplined approach as we look at opportunities to utilize it and how those would accrete to our shareholders' value. On the next slide, before we get into the 2023 budget, I want to spend a couple of slides looking at how that capital allocation strategy has resulted in incremental value for the shareholders since 2016. So as you could see, from 2016 through our 2023 budget, our adjusted EBITDA has grown about 18% when you exclude the contributions from the assets that we've divested in those years. Meanwhile, we've reduced our net debt by almost to 20%. And on the next slide, we'll show the remaining part of our capital allocation efforts. Our discretionary capital has been robust over the years. We have reduced the overall amount of annual spend in our growth capital program. As Kim mentioned, we're now more in that $1 billion to $2 billion range. But importantly, most of our projects, generally speaking, are on the smaller size, which are more capital efficient and come with higher returns. So a real quality-over-quantity type approach. And on the right-hand side of the page, you can see our dividends paid and our shares repurchased. After a few years of more sizable increases in our dividend, we've fallen into a pattern here of more modest but steady dividend increases, which we think are appropriate and are sustainable, while also taking advantage of opportunities to return value to our shareholders in the form of stock repurchases over that time. So past performance is not always a predictor of future outcomes, but track records matter, and we think this illustrates that we're doing what we said we would do and are following through on our capital allocation strategies. So moving on to the '23 published budget -- I'm sorry, one last page on this. This is really kind of illustrating the same thing, but just on a GAAP basis, I guess a couple of high levels here. Our free cash flows from 2016 through our 2023 budget has increased 50%. Our net debt, as I mentioned, is down about 20% over that same time frame. Our annual dividends have more than doubled and are now growing at a steady, sustainable pace, and we've conducted about $950 million of share repurchases along the way. Now moving on to the '23 budget. This is consistent with the guidance that we provided back in December, just with a whole lot more detail. And as usual, we're going to post this to -- or we have posted this to our website, and we'll compare back to it quarterly. So you all and we can track our performance versus our expectations. We budget to generate $8.2 billion of adjusted segment EBITDA. That's up 4% from last year. And last year was a very strong growing year. So good, healthy underlying business growth. Our adjusted EBITDA is expected to be $7.7 billion, up 2%, and we'll talk about why that's a little bit lower. It's partially due to a higher noncash pension expense that we expect in the year. And then our DCF of $4.8 billion, a little bit lower than last year, and that's mostly driven by higher interest expenses that we expect in 2023. We don't have any buybacks assumed in the budget, and we do that because our usual approach to share repurchases is an opportunistic approach, one that we require attractive repurchase prices before we actually conduct share repurchases. We don't do it on a programmatic basis, and that's why we don't have any of those assumed in the budget. On Slide 70 is our EBITDA bridge, and this is just to show you some of the larger moving pieces year-over-year. So first, we've included the headwinds that we expect on a number of our natural gas pipelines where we expect to have lower rates after recontracting on those assets. This is something we've been talking about for the 2023 headwind for a couple of years, and the magnitude of this impact is consistent with the prior disclosures. And so that's helpful, but also importantly, this is the last year that we expect meaningful recontracting risk on our assets for the foreseeable future. And the bar to the right quantifies the amount of favorable recontracting that we expect in the year, along with some rate escalations that we expect. But 2/3 of that bar is really favorable renewal. So if you combine that or if you just compare the favorable renewals against the unfavorable renewals, it's about a wash and as I said, the unfavorable renewals, we don't expect to reoccur going forward in any meaningful way. So nice to see the underlying base business growth and the value of our assets really shining through. The 2/3 of the favorable recontracting comes from our natural gas segment, MEP, our Mid-Continent Express Pipeline, favorable renewals on that asset, our Texas Intrastate favorable renewals and our Jones Act tanker business, as Kim mentioned, is having a healthy -- is expected to have a healthy 2023. Next, we show some unfavorable impact from our G&A and noncash pension expense. Some of this is higher labor costs, but the majority of this -- the vast majority of this is a noncash pension expense. This has to do with poor performance in our pension assets last year. So we're at a lower starting point this year, meaning the increase in asset performance in 2023 is going to be lower than -- or is expected to be lower than 2022. There's some complexity to pension accounting that we won't get into, but we think that this is illustrative of some volatility that we've seen in the pension accounting and pension expense category that we've seen from time to time. And we think a more consistent measure is the cash contributions that we make into our pension plan annually as opposed to the expense piece that's a GAAP function. So that's why we replaced the noncash pension expense with our cash contribution in our distributable cash flow metric, which ultimately, ours -- the cash contribution is a little bit more stable over time, but we've ultimately ended up in a similar spot as the GAAP measure. The next category are divestitures, and that's largely an impact of our partial interest sale in the Elba liquefaction facility. Then we have our significant growth from growth projects and some incremental volume expectations through our existing gathering and processing assets. Next slide is our interest expense slide. As we released in December, we expect some headwinds from our interest expense -- from interest expenses in 2023. We have $7.5 billion of floating rate debt, which means for every 100 basis point change in short-term rates, we have a $75 million exposure. We also had a -- we also had locked in a little bit more than $5 billion of our short-term exposure in 2022 that expired at the end of the year. We received about a $70 million benefit from those 2022 locks, which won't reoccur. So if you -- if you look at where short-term rates are expected to come out for 2023, which is about a little bit more than 300 basis points higher than '22, apply that to our sensitivity and add the $70 million of the lock benefit that we received in 2022, that gets you close to -- that gives you about $300 million of this $331 million. In an attempt to mitigate some of this impact in the year, we have locked in SOFR rates for about $1.25 billion of our floating rate exposure in 2023. We did that at levels that were slightly favorable to our budget so it will have a large move, but it also helps us mitigate some of the potential future downside risk should rates move against us. And we'll continue to take a look at opportunities to mitigate the risk and potentially improve on the budget. And finally, while this interest rates headwind in 2023 is very disappointing, it hasn't changed our view on the appropriate strategy for floating rate debt in our portfolio going forward. We think some portion -- some percentage of floating rate debt in our overall funding mix is appropriate, and it's created a lot of value for us over the years. We've generated $1.2 billion of lower interest expense over the last 10 years as a result of having this floating rate strategy. And importantly, the underlying fundamentals that have driven that improved performance as a result of having floating rate debt hasn't changed. We don't think that the swap forward curves that typically overestimate the short-term movement in rates hasn't changed. So we'll continue along with this strategy. On the next slide, on the top of the page, you can once again see that the primary differences between net income and our distributable cash flow are really 2 items. Distributable cash flow includes cash taxes, and it excludes book taxes. It includes sustaining CapEx, and it excludes book depreciation. So we view distributable cash flow really as a cash proxy for earnings and is a better -- therefore, a better representation of the cash-generating capabilities of our asset in our business. Moving to the bottom of the table, you can see DCF per share is budgeted to be $2.13. But as some of us were mentioning or were discussing before this, if we were to remove the interest expense impact from the year, the DCF per share would be $2.28, up 4% from 2022, which is consistent with the segment EBITDA growth year-over-year. Our dividend is expected to be $1.13 per share, which is up 2% from '22. It's greater than our DCF per share growth, but it's a little bit lower than our segment EBITDA growth. So we think that we're threading the needle pretty well there, growing it at a little bit less than our underlying business growth but a little bit faster than our bottom line cash flow growth. And we've maintained -- and we are still maintaining a healthy coverage level. On adjusted EBITDA, on the next slide, this slide provides a lot more detail into some of the key drivers in our segments performance year-over-year. I won't go through that detail, but would note that it's very nice to see that in each one of our business segments, we expect growth, which is very nice. The other piece is, if you were to exclude growth capital contributions from the 2023 performance, we would still have about a little bit north of a 1% growth rate year-over-year just based on the underlying business growth, not accounting for the capital-related expansion contributions. A couple of items here to highlight. Just to point them out, the G&A and corporate charges, they aren't -- that is up quite a bit. And again, that's the non-cash pension expense item that I mentioned before. the 25% year-over-year growth would actually only be about 6% if you were to remove that 1 item, which again we don't think is representative of the long-term cost for us. On sustaining capital, it's also a bit higher, higher by $101 million, and that's due mostly to increased costs related to our Natural Gas segment. The primary increase is from an increased number of class location changes that are going to be required in 2023. But there are also higher costs for turbine exchanges, pipeline integrity costs and some additional environmental regulation. And right below sustaining capital is other items, and this is where you can see we add back the non-cash pension expense item here and replace it with our cash contribution, which year-over-year is consistent. So DCF, as we mentioned before, down 3%, but more than all of that is explained by the higher interest expenses year-over-year. Moving on to CapEx. The top part of the page here is more detail on our sustaining capital budget. Moving into the discretionary capital section, you could see $2.1 billion of total discretionary capital expected for 2023, about $1.4 billion of that is related to our Natural Gas segment. And of that, if you look at the key projects on the right. There are 5 projects there that represent collectively about $1 billion of the $1.4 billion. The rest of the $400 million or $385 million or so of Natural Gas, along with most of the other projects across our other business segments, are smaller, more capital-efficient type projects. So as Kim noted across our full backlog, we expect an EBDA multiple of 3.4x. And this year's spend is illustrative of some of the higher return projects that we expect. All right. Moving on to the next slide. This includes our cash flow from operations, $5.7 billion. And this is all on a GAAP basis, which I know is important to many of you. And we walk from net income down to cash flow from operations. There's our GAAP CapEx number of $2.8 billion to get to free cash flow of $2.9 billion. And then after we pay our $2.5 billion of dividends, we're left with $336 million of free cash flow after dividends. And that, along with the balance sheet capacity that we covered earlier is what provides us with tremendous flexibility during the year. Speaking of our Sources & Uses on the next page. This is just a high-level summary of our overall Sources & Uses to let you see the biggest moving pieces there. Our cash flow from operations, $5.7 billion. We started the year with $745 million of cash on hand. We account for the JV distributions that are picked up in our cash flow from investing section. That leaves us with a need to borrow about $2.5 billion. We've already covered the main uses here, so I'll just make the note again, just like I said on the earnings call. We do plan to access the capital markets to address our funding needs during the year, but we do have a $4 billion credit facility capacity, which gives us the luxury of remaining patient to ultimately access and address some of these borrowing needs. Moving on to Slide 77. We expect to end the year at 4.0x, nicely below our long-term leverage target of around 4.5x. And the only other comment I'd make on this slide, as you can see on the right-hand side, we're nicely -- we drop off nicely after the wood we have to chop this year, we're below $2 billion in total maturities every year for many years. So that's good to see. Moving on to our quarterly profile. As we mentioned every year, our quarterly shaping is not even across the year, and it's primarily due to 3 things. In our Natural Gas segment, we have some pipelines that have greater performance, greater contributions in the first quarter and the fourth quarter because during the winter time, we generally see higher rates and higher utilization on a number of those assets. And so that provides greater contributions in the first and the fourth. And then in distributable cash flow, we have 2 additional factors that play in. One, estimated cash tax payments, we have 0 in the first, 2 in the second, 1 in the third, and 1 in the fourth. We also tend to have less sustaining capital in the first and then more consistent sustaining capital in the second to the fourth. And so we've provided more detail on the quarterly shaping this year than we typically have. So hopefully, that's useful for you all to calibrate your models as we go through the year. All right. Slide 79 on our minimum book tax. First, under the traditional federal income cash tax based of -- part of this, we are not expecting to be a federal income cash taxpayer in 2023. And just like last year, we don't expect to be a material federal income cash taxpayer until after 2027. Now on to the incremental potential federal taxes, the minimum book tax, which was just passed last year, we don't expect the minimum book tax to be applicable to Kinder Morgan in 2023, 2024 or 2025, and that's just a function of us looking out. And it's a complex calculation, but it's our view of the applicability to the $1 billion threshold, looking at our taxable income and our overall tax depreciation mix. As I said before, it is a complex calculation. We'll continue to monitor it, and we'll update you as necessary. But that's our current view right now. Slide 80 is our budget sensitivities slide. And this page is really for your reference. I wasn't planning on spending any time on it. Slide 81 are our highlights. And so really just to wrap up here and let you all get to your break, we beat our budget in 2022 by 5%, both on an EBITDA and a DCF basis. We increased our dividend by 3%. We reduced our net debt by $300 million. We ended the year with the lowest year-end net debt balance since our 2014 consolidation transaction, and we repurchased almost $370 million of shares at an average yield of 6.6%. So a pretty decent return even excluding the terminal value from the elimination of those shares. And for 2023, we expect a 2% dividend increase, a further reduction in our net debt, an improvement in our leverage ratio to 4x and we have plenty of excess capacity which gives us lots of flexibility should we see opportunities and cushion should we see any risks. So outstanding performance in 2023 and very well positioned -- excuse me, outstanding performance in 2022, very well positioned going into 2023, and we have some firepower. So with that now, now it's time for the break. So...

We'll take a 10-minute break. So start right back up at 11:10. We'll bring our business unit presidents up here, and we'll start the Q&A session. Thank you. [Break]

Okay everybody, 30 seconds. Thank you, everybody. So what we're going to do here for the next 30 minutes or so is give you all an opportunity to ask questions directly of our business unit presidents. I know I probably interrupted you from doing exactly that while you were out there at the break. But in any case, this is where the work gets done. This is where our commercial strategy and our operational strategy and everything is getting executed. And so I think it's important for you as investors to hear what these folks have to say. So that's what we're going to do. So while you're thinking of questions, I got a question, we'll kick it off with for each of the presidents. And then we'll open it up to questions. And so I'm going to hit on things that are really -- some of our most frequently asked questions. So hopefully, that will be useful. And then we've got microphones that we will get around to anyone who has a question here in the audience.

So I'm going to start with Natural Gas. And Tom, Tom Martin, President of our Gas Group, as you know, your base business has turned the quarter in the past year. Now seeing some increased rates on renewals, what's driving that? How do you see demand for storage and transportation trending going forward?

Good question. I actually got that one on a few side bars already. So I know a lot of you are interested in this one. And as David noted in his presentation, this is the last year of meaningful unfavorable re-contracting risk for the foreseeable future. As you recall in past presentations, we've been showing you kind of the 2 prompt years of what that risk look like going forward. And there, although not material in the whole network perspective, it was material or meaningful for those particular assets involved. And those are primarily single-source supply pipes with point-to-point deliveries, no real demand associated with them, no customers directly connected. So all of those have reset now. And now the way to think about it is the rest of our network, for the most part, is an integrated supply and market network with direct users, end users at the end. And as David noted in his presentation, the uplift on renewables now slightly more than offset the last bit of unfavorable re-contracting risk. So that's evidence to what was mentioned earlier that we're starting to see increasing values, longer terms on renewables for our transportation and storage services, really that we didn't even see a year or 2 ago. So I think there's some momentum building here. And then as far as the fundamental drivers behind that, I think we've covered that in a lot of material. But it's the LNG export growth that we've seen, and that trend will continue for many years to come. And in the midst of that, we're still seeing supportive demand in our power gen, industrial and Mexico export businesses. And then the permitting and regulatory environment that we see in some parts of the country make it extremely difficult, if not impossible, in many instances to add new infrastructure. And so -- and that's primarily outside of Texas and Louisiana. And so as demand in the market overall grows, the value of existing infrastructure, both pipeline capacity and storage, grows with that growth. And then the last thing I would say about Texas, even though we have a little more friendly environment to build our network and last-mile connectivity and storage position in Texas gives us a unique advantage to extract value there and provide services that many of these greenfield new pipelines can't do in that market. And then last thing, we talked a lot about the intermittency of renewables. We see that trend start from the West Coast and heading towards the East Coast and every market that we've seen that go into where we've seen 30% penetration or greater of intermittency. Not only just on a regular day where you have such a huge drop-off of renewable, whether solar or wind. But then when you overlay that with weather events, whether it be extreme heat with no wind or extreme cold with no wind or solar, then we've really seen the need for natural gas pipeline and storage capacity needed to backfill those demand needs. And so you stir all that up, I really feel very strong about the growth of our network and not only for project opportunities. But I think base business, I see some green shoots in our base business values, both for transportation and storage rates as well as term on our contracts.

All right. One quick follow-up from Tom. Many of you know that on our EPNG system, we've had some repair and testing work that we've been doing on our Line 2000, and we have an update as of this morning on that. So Tom, why don't you cover that quickly as well.

So we talked about this on the earnings call that we expected to be completed with our work and submitting our request to return to service to FEMSA. And in fact, we have completed that work, and we submitted this morning that request to FEMSA. And as we said before, it's going to take them some time to digest that and evaluate how fulsome that all is. But we feel good from the perspective of the work we've done. And we feel we've done well to meet the expectations and requirements of the CEO. So we'll see how long that takes, FEMSA. And we'll certainly give you an update when we learn more.

So that update was posted on our El Paso EBD this morning. Next question for Dax Sanders, President of our Products Group, about the renewable diesel opportunity. How much potential is there to do additional RD beyond the 2 current California hub projects that come online this year? And how expansion of RD supply impact your existing business?

Yes. Good question on the RD front, and that's certainly something we talked decently about. Starting with just maybe starting with level setting where we are right now, consistent with what Kim walked through, we've got right around $70 million worth of projects in our backlog right now related to renewable diesel. Now we talk about the 2 hubs in Northern and Southern California, those are about $50 million of it. And then we've got another, call it, 20-plus of what I would call other associated projects: Tank conversions, ancillary services, things like that. We actually have -- we've actually got a 100-year-old crude oil tank that we're converting to renewable diesel, if you can imagine that, in Los Angeles. So that really is kind of where we are right now. And again, with our hub projects, they create about 40,000 barrels a day of RD capacity. And we've got take-or-pay contracts for about 31 right now on that. I think we'll probably end up terming up a little bit more of that. The balance of it, we will keep as spot capacity. And so our ongoing dialogue suggests with customers that they're going to want additional capacity, particularly as some of the domestic refining capacity conversions that are happening come online. Certainly, right now, we've got BP Cherry Point up in the West. And then we've got both the Marathon and P66 facilities in Northern California, which are in the Bay Area. And those are kind of a mix of producing a little bit of renewable diesel right now, as well as coming online with their full conversion projects. As I've said in the past, right now, and as Kim said, all renewable diesel right now is gravitating towards California. It all wants to go there. And that all is a product of, sort of, the well-developed 3-layer tax credit. Everybody gets the 2 layers from the federal perspective. And then California, the LCFS that California has, makes it the most lucrative to go to California. There are other states and particularly in the West that are putting in place state credits that are starting to, I think, create a lot of interest with people. Oregon's probably the furthest along that's creating additional interest. And Washington State has got one as well, probably not as -- still needs a little bit of developing. But the dialogue that we're having with our customers certainly is still centered on California, but we hope that -- and part of this has to do with availability of supply. Because as you all know, the supply is not as abundant as it probably will be at some point. But our customers have increasing interest in other areas. Now if you look at our footprint across the West, we've got a really good footprint across the entire Western United States. We -- in addition to California, we've got a couple of terminals in Oregon. But in Nevada and Arizona, we supply the majority of refined products across the board out of those states. So to the extent that those states put in place similar type regimes that drive demand for it, I think we're really well positioned for that. And just to put a finer point on it, I think it's important to put a finer point on the value that we add. With respect to renewable diesel, if you're blending 5% into the stream, you really don't need to do much beyond the point at which you blend it. So our customers blend the 5% in, and they get the tax credit. But above and beyond that, the concentration of it has to be tracked all the way to the fuel pump. And so transporting any concentration above 5%, even up to R99 requires a lot of thoughtful handling and segregation of product, including interface in the pipeline. And so that's really where we come in is having the infrastructure to be able to track it and handle it all the way through and process the interface. And so what we're able to do is charge a fee and earn an extra fee for segregating those volumes and maintaining the integrity of the stream and the tax credit. And so anyway, we believe that we said a couple of years ago that we thought the opportunity set would be somewhere close to $100 million over the next couple of years. We're right on top of that. And we certainly hope as supply becomes more available, and our customers become more enthusiastic about renewable diesel and other places, that will transcend the opportunity in other places.

All right, very good. And going to the other end of the renewable fuels, liquid fuels chain, John Schlosser, President of our Terminals Group, renewable feedstock hubs, how is the NESTE project going?

Luckily, a lot more good than bad in regards to this project. As Steve mentioned earlier, we have 2 of the 30 tanks came on this past Monday. The remaining 28 will be rolled in as the quarter progressed. The projects team has done an absolutely outstanding job managing supply chain issues, material cost pressures. We are showing an increased amount of spend on this to $80 million from the original $65 million. But much of that increase is attributable to project scope additions and enhanced model capabilities that the customer NESTE specifically requests. So the returns are very comparable to what we originally had discussed from a percentage standpoint. But more so, and Kim alluded to these, though we're real pleased with the direct, it's really the indirect that has surprised us to the upside. And what were those? So the return is great. but we were able to and we hypothesized that all ships would rise as we were able to attack this project at our 3 million-barrel Harvey facility. But we actually have performed significantly better than what we anticipated. So as we're re-contracting the existing customers, we've been able to: One, do it at a much higher rate; and two, do it for a much longer term from a year's standpoint. And just to give you a feel, and she alluded to this, and this facility was significantly challenged within our portfolio. We were trying to figure out what's it going to be when it grows up. And so historically, you were looking at less than 1-year contracts. Oftentimes, we saw utilization in the 60% and 70%, and rates were fairly compressed. So what we've been able to do is high-grade all of the existing customers there, push price up and get much more term on it. To the point now where we're looking at almost 100% utilization as soon as this project rolls into play. The knock-on effect though has been the projects that you see on the far right here. We saw opportunities to make additional investments on behalf of customers at Harvey. And also to look at another feedstock hub at our River -- our Geismar River terminal north of Harvey. And that project is with REG/Chevron, as was mentioned. Very good return under a 10-year agreement. And it's clear to me that our customers value our ability to deliver on these, and we're seeing more projects come to fruition because of it. A couple of years ago at this meeting, I mentioned the great bones of our assets. And I was talking about the 75 terminals, the 78 million barrels, the 266 ship docks, 462 truck bays, et cetera, et cetera, et cetera. And the reality is, it's always easier to do a project when you're using some existing infrastructure than when you have to build at all greenfield. And so I believe, as Dax does, that there will be more projects like this, and we hope to replicate these in other parts of our network.

All right. And as the NESTE CEO told Dax and you and me and Mike Garthwaite in a meeting, you can't electrify everything. We're going to need it for long-haul truck and we're going to need it for aviation. So good to be in this on both ends of that spectrum. Okay. Anthony, oil production outlook. Is it possible to continue extending out the productive life of your EOR fields?

Yes. We've consistently been able to extend the life, the production horizon at our enhanced oil recovery fields. We do think there's also a modest opportunity for future growth there as well. A lot of this is related to increased experience that we have with these mature fields and understanding of the geology, also utilization of innovative technology and processes, including advanced seismic. Certainly, recent -- more recently, the higher oil prices have helped as well in creating more economic projects. And we've had a great deal of success, I would say, especially recently at SACROC with our development projects. This helped us with our 2022 budget net oil production by 5%. We ended 2022 just under 2% lower than our 2021 levels. And we're budgeting for just about a 4% reduction in that oil production from 2022 to 2023. And so we've been able to manage declines at our fields, I think, to a very low number, low single digit percentages. And a good analog, I think for this is what you're seeing on the screen right now, our SACROC project. Every year, we kind of show you our production forecast. And every year, we kind of managed to shift that out in time. And so this year, not only are we shifting that production forecast out in time. You'll notice that the rate of decline there is much flatter as well. So that's due to a lot of the efforts that the team has been making. As Kim mentioned, our other big field is at Yates. Yates has been producing oil for almost 100 years now, and its decline rate is less than 4%. So we've got some great fields that we continue to keep producing. And then as Steve mentioned earlier, we do think there is a long runway for demand for oil and gas production, both in the U.S. and globally and for the right economics. And just to be clear, that means returns which are well in excess of what we would target for our Pipeline and Terminals business, we are interested in new EOR opportunities, especially in the light of the development of the CCUS market.

All right. And also for you, Anthony, on the ETV business. How and over what time frame can renewable natural gas and carbon capture and sequestration scale?

Yes. As Kim mentioned, we've made 3 acquisitions in the last 18 months. So we've been very active there. We have -- we now believe, a strong platform to grow off of. We have a good experienced management team with our Kinetrex folks. And really, right now, our focus is on project execution, as well as organic growth. We have 14 landfill biogas assets, inclusive of the RNG plants that are under construction right now. And that, we believe, puts us kind of in a leadership position within still a very fragmented space. And we've been able to achieve that at an attractive multiple. On the CCUS side, we've been talking obviously about the Red Cedar project today. In general, though, we believe the development cycle for CCUS is going to take longer. It's going to take longer to ramp up that scale. And that's for the fact -- some of the factors that Kim went over earlier: Longer permit time lines; there is newer technology that's being utilized in the capture space; potentially you're going to be needing new pipeline infrastructure; and the contractual arrangements can be quite complex to work through. With Red Cedar, we were able to expedite that process. It is utilizing our existing infrastructure in place. As well as because we are capturing CO2 off a natural gas processing facility, we're able to permanently sequester that CO2 in a Class 2 well. And that process is a much shorter process than the Class 6 permitting process. And we do think there are more opportunities for high end Red Cedar to do something similar. They are, in general, smaller scale types of opportunities. When we think about our larger scale opportunities, those are centered around the Gulf Coast, some in the Midwest. Those will require to be subject to the Class 6 permitting time lines, as well as will require new infrastructure. So again, we'll take a little bit longer to ramp up the scale in this business. We do think we are going to be a leader in this space. We are the largest transporter of CO2 in North America. We have been injecting CO2 in the ground safely and efficiently for decades. And as Kim mentioned, we can participate and have the flexibility to participate across the CCUS value chain. And so we think we're a very attractive partner of our folks out there.

Okay. All right. With that, if you've got a question, put your hand up. Somebody will put a microphone in it, and we'll take questions from the floor here, up here, to in here. Somebody back there already has a microphone, who does? Here we go, go ahead.

Neel Mitra, Bank of America. I have a question. You raised your expected exports to Mexico, the Natural Gas side from 7 to 9 Bcf a day. It seems like there's a lot of initial activity going on with West Coast LNG in Mexico. Could you see a path towards expanding parts of EPNG? And then on the other side of it, how are you looking at Agua Dulce and possible exports down the southeast side of Texas?

Very good. Tom?

Yes. So we are looking at opportunities to serve Mexico, both for LNG exports and also industrial growth, actually even more near-term opportunities there. So I think there are some projects that we're pursuing, we're certainly looking at from a development perspective of EPNG on the U.S. side, working with potential partners in Mexico to serve those [ loads ]. And then as far as Agua Dulce is concerned. I mean, certainly looking at opportunities to serve Mexico and any other markets and even potentially on the U.S. side, to de-bottleneck. But that area as you've seen, the Permian projects that have been kind of moving towards that location, certainly in need of demand, whether it go to Mexico or to LNG along the Gulf Coast to de-bottleneck that area, and we're actively working both of those opportunities.

Gabe?

Mizuho. I had a question on the Haynesville CapEx on the pipeline side. You had $265 million, I think, budget for this year. I'm just wondering -- does that include everything well connects and soup to nuts? And then also bigger picture, where does that get you? Does that get you ahead of the production profile that you're expecting for the next year or 2, or just a level of CapEx we should expect kind of year in, year out, if it continues to ramp? And then just bigger picture also whether you'd ever consider kind of a long-haul egress pipeline at the Haynesville and participating in projects like that?

Yes. Good question. So the $265 million really does cover all of our needs for 2023, including well connects and all associated expansions on our KinderHawk asset in the Haynesville. Yet to be told as to -- or seen yet as to whether we need additional capability, we're in active discussions with customers in that basin to attach additional volumes. I don't think it will necessarily in' '24 be of that scale, but we certainly are looking at other opportunities to potentially bring additional volumes on to KinderHawk even after 2023 as those -- as that market continues to grow. And then to your other question, yes, we're -- nothing imminent. But we are certainly working egress opportunities from the Haynesville down towards the Gulf Coast, both from a greenfield perspective. And looking at are there other ways that we can expand our footprint, whether it be TGP, NGPL, SNG, to take on more transmission volumes from that basin. We do have some underutilized capacity on TGP, which certainly is benefiting from the growth there and expect that to continue. And then certainly, as contracts come up for renewals on those assets, we would expect better values on those as they come up, even if we're not able to deploy any additional capital there.

Okay. Brian? Who is Brian?

Brian Reynolds from UBS. Maybe to start off on the Permian growth expectations of [ $10 billions ] by 2030 and the 9 Bcf per day of LNG supply that Kinder is pursuing. Maybe just in the context of capital allocation in the $1 billion to $2 billion of growth CapEx run rate, how should we think about that going forward? Could that move up? And then how do we ultimately think about the $4 billion of balance sheet capacity to help support some of those maybe perhaps larger growth projects, going forward?

Tom, why don't you start? And then David, if you want to add.

Yes. I mean I think from a business unit perspective, we're -- our job is to bring the best -- highest returning most actionable projects that we can to the leadership. And we will certainly continue to do that. I think what I believe whenever -- from my experience with the company over about 20 years here, whenever we've found good opportunities to execute at great returns, we find a way to do it, whether it fits within the $1 billion to $2 billion a year or we find partners that we want to work with to help get the project executed. So I'm not as worried about capital capability there. We usually find a way to execute well when the opportunities avail themselves at of attractive returns.

Yes. In terms of our annual capabilities of funding, we're at the $2 billion or even a little bit north of it given some of the growth expectation beyond 2023 that we have baked into our longer-term forecast. I think we have some additional capacity that we're going to generate. So even if we're a little bit north of the $2 billion on the high end of the growth capital budget range that Kim mentioned, I think we should be able to fund that mostly or entirely with cash flow from operations. But to Tom's point, should we have greater opportunities in that, then that meet our investment criteria? We've been able to find a way to fund those. And we think that is in the best interest of our shareholders should we have greater opportunities than what we can fund internally. It is in the shareholders' best interest for us to find a way to accommodate those.