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

Okay. If we could, let's get started right on time. Good to see all of you who are here in person, and welcome to everybody who's on the webcast. I hope today we'll return. So that this time next year, we will have a room full of people without having to sit 2 yards apart and all that, but that's something beyond our control. But anyway, welcome. We've got a full program for you this morning. And I hope, as usual, you will appreciate and understand the transparency that the team is going to show you today, looking at '22 and beyond. Turning first to the slide on forward-looking statements. This is a typical slide, obviously, but we urge you to review this in our SEC filings for risks that could materially affect our expected results that we will be talking about this morning. Let me give you kind of an overview. First of all, as I indicated, I trust and hope that the team will deliver its usual deep dive into the Kinder Morgan story. And I think you'll come away with the impression that the outlook is really positive for 2022 and beyond for this company. But I want to begin by taking a high-level look at the Energy segment and KMI from an investor standpoint. Notably, it seems to me that the market is beginning to look at the Energy section -- sector in a slightly different light. It's starting to recognize the increasing financial discipline of the players who now prize living within their means and delivering real bottom line benefits to their shareholders, and that's been our mantra for a long time. I think the market is also seeing that the sector is being very proactive in being part of the energy transition, and that also applies to us with our efforts on RNG and other areas. And very importantly, I believe, investors are starting to realize that the energy transition is going to be longer and much more complicated than many originally believed. In short, I think the recognition is now beginning to be out there, that there's a long runway for fossil fuels and for natural gas in particular. Now talk is always cheap. The real proof for my thesis, I believe, is that the energy sector was the best-performing sector in the S&P 500 for 2021, and that trend is continuing during the first few weeks of this year despite a pretty dismal performance in the overall market that we're all witnessing. Now Kinder Morgan has participated in this rally, although not to the extent I feel appropriate, by delivering a total return, including dividends of about 24% in 2021 and an additional positive return thus far in 2022. It seems to me that the biggest advantage that KMI delivers is a huge cash flow, and the ability to use that cash flow for maintaining a solid balance sheet; funding capital expansion projects with good returns; increasing our dividends, and '22 marks the fifth consecutive year of increases; and buying back shares on an opportunistic basis. In substance, we are providing our owners a high degree of optionality while providing, I think, a safe harbor in the storm we are seeing in the general market today. So that's kind of an overview. Let me turn to some slides that explain where we're going from an investor's perspective at Kinder Morgan. The first slide shows that we have a huge footprint. We show this every year. And as we've said so many times, having this size of footprint across all of our business segments leads to economy of scale and opportunities for step-out expansions. We have the largest natural gas transmission network in the country. We move around 40% of all the natural gas consumed. We're the largest independent transporter of refined products. We're the largest independent terminal operator. And we're the largest in terms of CO2 transport capacity. In addition, we also now, when our present projects are completed, we'll have about 4 Bcf of RNG production capacity by early 2023. And I think you can expect that capacity to expand as we go forward. That's an area that's of great interest to us. And if you look down at the bottom, you see the business mix as it always has been for several years. We are oriented most of all toward natural gas, which I believe has the longest runway among fossil fuels in North America. It happens to be on February 14 of this year. It will be the 25th anniversary of the founding of Kinder Morgan, and I thought it would be interesting to show you this slide. Obviously, things have changed a lot in terms of miles of pipeline, in terms of enterprise value, in terms of employees. But I would circle for you, the bottom 2 parts of this slide, the CEO salary has stayed the same. I earned $1 a year. 25 years ago, Steve earns $1 a year today. So that hasn't changed. And I'm also proud of the very bottom line, we don't have any corporate jets. We didn't 25 years ago when we couldn't have afforded them, and we don't have any today. So I think what we try to show by this slide is that while past performance is no guarantee of future success, hell, we all know that, but I think we want to show you that management remains aligned with the shareholders. I think that's been a real important perspective and important part of the Kinder Morgan story. So the next slide really talks about that. We talk a lot about the fact that we have big insider ownership. 13% of the company is owned by management and the Board, and that's impressive. But I think, really, this whole slide shows you a mantra that I've always believed in any investment, which is that it's best to invest pari-passu with the people who are making the decisions, and that's certainly the case here. And beyond this ownership, 13% ownership by insiders, we also have an equity-based compensation system. I think it's key that 68% of our executive compensation is delivered in restricted stock. Again, we are placing our executive team, pari-passu with the rest of our shareholder community. I think the last bullet here is also important in terms of discipline. We have tried to maintain ourselves as a low-cost operator while maintaining self and compliant operations. We've really inputted severe, I would say, severe high-return criteria on our capital projects. We are not spending things just because it seems nice to spend. We're doing it only if it produces true bottom line results to our shareholders. And finally, as we've said so many times, we work hard to return our excess cash to shareholders through a growing dividend, which is also very well covered. You can see that from the statistics and through opportunistic share repurchases. Now let's talk about free cash flow. That's certainly a metric that is getting increased emphasis across the whole investing spectrum, certainly not just in the Energy segment and rightly so. And I think the Energy sector and Kinder Morgan in particular scores very well in terms of this particular metric. If you look at the left-hand part of this slide, as you can see, the average free cash flow yields for 2022 estimates is highest for Energy beyond any other segment of the S&P 500. And then if you go to the right-hand part of this slide, you can see where Kinder Morgan fits in. This is based again on '22 consensus estimates, which would show a free cash flow yield of 10% for Kinder Morgan for 2022. That puts us in the 92nd percentile of all S&P 500 companies in terms of free cash flow. If you look at returning value to shareholders, Energy leads the way again there with an average dividend of 3.3%. Again, we are an outlier in a positive sense there. At 6.2%, we believe we have the sixth highest dividend yield in the S&P 500. And so in essence, if you look at Kinder Morgan as a story, it's a story of optionality and you're getting paid very healthy and well-covered dividends while we explore and take advantage of those options that have become very apparent to us. But some say, well, it's not enough to pay dividends. Your cash flow is not good enough. I want something sexier. I want something better. I want something that enthuses me. So what about M&A? Why aren't you out there looking at M&A opportunities to pursue? Let me just say that Steve and Kim and the team constantly examine all kinds of alternatives in terms of M&A. But let me make it very clear that at the board level and the management level, we're only going to do M&A if it makes sense for our shareholders. We're not interested in buying a hockey stick, and we're not interested in doing anything that will jeopardize the kind of progress we have made over these last 5 years. So if you look at us as a whole, we have a 30 -- we have a market cap that's almost $40 billion today. As I said, we're heavily owned by management. We have $7.2 billion of adjusted EBITDA for 2022, and that's an increase of over $300 million from 2021 if you strip out Uri. We have a good dividend yield, as I said, above 6%. And we have a share buyback program, which has over $1.4 billion left in terms of capacity. So for all these reasons, from an investor's perspective, it seems to me that Kinder Morgan has a lot of value to deliver both in 2022 and beyond. And with that, I will turn it over to Steve, and we'll go through a lot of the details about 2022 and beyond. And I think you'll come away increasingly convinced that this is a positive story. Thank you.

All right. Thanks, Rich, and good morning, everybody. I'm going to start off by talking about our future, really the broader energy environment in which we're operating and where we see our opportunities there before getting into some of the specifics. So we'll start, as we always do internally, as well with our vision, our mission and our values. And so this isn't something that just came down from on high. We put a group of people together to really talk about our why and our purpose from across the organization. And this is what everyone agreed on as the right approach, delivering energy to improve lives and create a better world. Acknowledging that affordable and reliable energy is essential to human development around the world. What we do is important. What we do matters. It's what helps people get around. It's what keeps the power on. It's what lights and heats and cools homes. It's what powers factories. What we do is important. As I tell our folks all the time, you make civilization possible. And when people ask you what you do at Kinder Morgan, you tell them, I make civilization possible and you're welcome. Okay. So we believe we're positioned well for the future of energy, both in what we do today and how we can pivot what we do today and then what we can do in the future, what we can add to that in the future. I think we'll get into some of the details here. But the U.S., you think about this, the U.S. is the world's most responsible producer with scale. U.S. exports help meet global demand and growing economies that are in need of what we have here today, affordable modern energy. Natural gas, as I'll show in a second, can rapidly lower emissions. It's done so in the U.S. It can do that around the world. And flexible storage and delivery of natural gas, important thing to get across. We're less about how many molecules and more about what's the call and the need for what we do, which is provide firm transportation and storage flexibility to meet variable demand. Our assets also, because of that characteristic, facilitate renewable blends with traditional fuels. We can do that in both our liquids business, and we also do it by backstopping in the power business, backstopping renewables. So for the future, many of the emerging renewable fuels are things that we can handle today. We can fit renewable diesel in our pipes and in our tanks, just like we can, regular refinery diesel. We think our existing infrastructure, pipe in the ground, assets on the ground are going to be valuable for a long time to come, particularly in an environment where it's difficult to get new stuff permitted. We can repurpose our assets. We're doing that with renewable diesel ultimately after solving some technical challenges. That may be an opportunity with hydrogen as well. But we're going to take a very disciplined approach, as Rich emphasized in all of this. We're not chasing press releases here. We're going to do things that make sense, that fit with our view of where energy is and where it's going, and it will deliver attractive returns to our investors. So if you look at the people who were doing the fundamental analysis here and the people who are paid to be right about this, what you see is with growing energy needs around the world, there's going to be all of the above and there's going to be more of nearly everything on this page, except for coal. So when you look ahead to 2040, you see renewables growing certainly, but you also see natural gas growing. You see other, which includes, by the way, renewable natural gas. And you see oil products growing. So to meet the world's energy demand, and we'll talk about how we're positioned for those exports, to meet the world energy demand, you're going to need more of everything. Here's another important thing. On the right-hand side, and this is where that growth is coming from, so you can see a lot of this is directed at the export markets. That's where the real growth in energy consumption is coming from. The other important thing to notice about that is the top folks on the Asia Pacific, which accounts for the biggest piece of it. 55%, Africa, the Middle East, Central and South America. These decisions about what's going to be needed for energy -- to meet energy needs of tomorrow are not being made in the United States or North America or Western Europe. They're being made by the countries and the places where people are trying to pull more people out of poverty and give people a better opportunity at a productive life. We're a responsible producer, as I mentioned at the beginning. Only 5 countries have lower emissions intensity factors in the United States, and the United States produces more energy than all 5 of those combined. You see that on the right-hand side. The U.S. is going to play a big role in meeting global energy demand, as you see on the left-hand side, which is focused on the liquid fuels, oil and petroleum and other liquids. If you look at the different years there, you see 4 million barrels going to 7 million barrels a day by the time you get to 2040. It gets to 6 million by the time you're in 2030. That's going to be -- that is the implied export value there between the domestic consumption and the overall need. U.S. natural gas is a similar story. You see the amount there, the gap, the implied exports growing from 12 Bcf a day up to 24 Bcf a day. Now I want to make one just general point about the inflection point and the turnover that you see decades out, but you see a rollover there. And I would just -- and so this is third-party analysis. We do our own look at this too. But I would -- to the extent you look at these things and you're trying to think about things like terminal value, I urge you to look at the underlying assumptions in those forecasts and in those estimates. Oftentimes, there are some pretty significant and important assumptions, particularly around renewable energy and around battery technology. And you need to just ask yourself as you're examining those and thinking about the breakthroughs and technologies that are implied but not here yet, the amount of minerals that will have to be mined from mines that are implied but not here yet, okay? And think about whether you believe that really, even when we get out into those 20 and 30 years from now timeframes, we're really going to see the kind of transformation that's predicted. But in the meantime, for the near term, what we see for our -- what we're concerned about is a growing need for energy exports. And if you look at our facilities map, you can see that we're really wrapped around -- our assets are wrapped around those export markets. And so more to come on that. The search for solutions is not over here. We're going to need other things besides renewables. So a couple of examples that highlight what I was talking about, the distinction between what we do as Kinder Morgan, which is not so much about producing the commodity as it is about making sure that it is transported to where it's needed on a firm basis, and that we have the storage that's required to meet the variable demand. And that shows up in a couple of places. The first one I'm going to talk about is backstopping renewables, and we have a significant role with our assets in the natural gas sector, in particular, for backstopping renewables. And then I'm going to show you an example that relates to severe winter weather. The one on this page is looking at a period of time in California when the call on natural gas grew. And you can see that in the salmon color areas there. You see the top line represented the total energy consumption. You see it coming up and down. And you see how the variability is really filled in by natural gas in that chart. And that need continues to grow, meaning the call on firm capacity continues to grow, the more you put renewables in the generation stack in order to meet the end-use requirements. So it makes storage more value. It makes the call on energy transportation capacity more valuable. And you can see this happens from day to day and intraday as well. So the ability to provide a firm backstop solution is it grows in value, I would submit, even faster than the commodity value itself. So in this particular case, you saw natural gas increase significantly, 84% over the prior week in order to meet demand. Power was still curtailed, and so what would be required is additional contracting for firm transportation capacity, firm storage capacity and making sure that the power generation capability is there to undertake it. So if that had all been done, then curtailment might have been avoided. And wisely, I think, California decided to add 120 megawatts of gas-fired peakers to meet this peak demand. And I think that's a story you're going to continue to see unfold. If you go to the next page, you can see a similar thing for winter weather. This is the Texas experience during Uri. It's a little bit complicated here. But just to simplify it a bit, what we saw in the left-hand chart was massive storage withdrawals, okay? That's what happened. There were widespread freeze-offs in the Permian Basin. And the way essential demand was met for the power sector and for residential and commercial was by pulling gas out of storage, and that's what we did. We run max withdrawal from storage, even as 2 Bcf of Permian gas, another 2 Bcf from another pipeline and KT deliveries all went to 0. In fact, KT deliveries actually went negative, if you will, because we were selling into KT to try to serve with our storage, North Texas markets in Austin and San Antonio. So storage is extremely valuable, not only to backstop renewables but also to encounter extreme conditions -- extreme weather conditions. A little hard to sort out there, but the kind of dotted black line there shows you the temperatures. And you can see as temperatures decline, gas consumption is filling in a gap. At the very beginning of this period, at the very bottom, you see wind and solar dropping off. Our solar is just part of the day anyway, but you see the freeze-offs that impacted that. And gas is what really made up the difference and made it less of an issue than it otherwise was. And it was already a bad situation. Then you see storage withdrawals dropping way off. Temperatures went back up into the 60s and then it was turnaround time. All the gas started coming in from the Permian. It was sunny in Houston, and storage injection became incredible -- incredibly valuable. And so the whole situation turned around. Again, firm transport, firm storage, the call on that to meet variable demand in the energy sector is what makes our assets valuable. Okay. So this is maybe a little bit of a provocative title. But the point is simply that in order to meet all of the energy demand to serve growing developing markets around the world, it will be a lot more expensive. And so you have to think of these economies, the same economies you're trying to pull as many people out of poverty as they can and give their populations a better life. It's the same decision you and I would make if we were in charge, right? Those people are going to be expected to pay significantly more. And these bar charts on the left are in trillions of dollars, significantly more to achieve the same GDP growth. That's the main point. Now look, that can happen, but it's just something to give you some perspective on what will be required in terms of commitment and from whom it would be required and what they would have to be willing to sacrifice in order to be able to do that. I apologize, the rest of this is a little bit of an eye chart, but that's because I asked the IR team to slam it all onto one slide. But in the middle, what you see is the requirements for clean energy technologies, and this is expressed in millions of tons. And the first bullet underneath there, if you look at it, this is over 50 new large-scale lithium, cobalt, nickel mines that would have to come into existence that don't exist today. And the experts would say that roughly from resource discovery to full exploitation is a decade or more. And so when you think about that, we're going to build 50 new mines that are world-scale, don't exist today, and that's what's going to be required in order to meet the mineral requirements of the energy transition. And on the right, you see where it comes from. On the right-hand side -- on the left of the right-hand side is where the extraction is coming from. And you see the top 3 producers amount to 75%, including cobalt coming predominantly from the Democratic Republic of Congo and rare earth metals coming predominantly from China. And then on the right-hand side, you see processing -- the processing of those extracted minerals. And by far, the largest processing capability is in China. Now this isn't to say that supply chains can't be solved and everything else. This is just to point out that this is complicated. This is not just a matter of will, right? This is a matter of a lot of things coming together to replace large parts of an energy infrastructure that was built over a century, okay? It won't happen quickly, and there are going to -- therefore, there will be a need, as I said before, for an open mind for more solutions. So putting it all together, back on Page 14, where the demand growth is coming from and who's going to make the decision, on the left-hand side here is a very expensive way to give people more of what they need to come out of poverty and to have a better life. In the middle, you see the huge shift from what is a fuel-intensive energy sector to a very materials-intensive energy sector, which has its own issues, as you see on the right. Geopolitics will be challenging for the supply. And so there is a better way to help solve some of this and get to that in just a little bit. So I mean, I just ask everybody, as you look at all this and you think about transformations in other industries that you know and in industries like energy that you know, and put on your plausibility helmet and ask how likely this stuff is to come to pass and by when, and by when. All right. The next page, I talk more about the benefits of natural gas. It is low emissions. We see that and how it's played out in the United States. It's reliable, which is critical for power, to keep it on all the time, not just some of the time. It can be dispatched quickly. It's abundant and low cost. We have it in the United States. We have the world's best infrastructure to get it out. We've got the people who can do the work to manufacture the equipment and facilities that are needed to drill the wells to do all of that. If you come to the United States, hundreds of producers will meet you at the doorstep trying to sell you their product. It's energy dense and efficient. It requires less land use burden. So we can have economic growth in human development without sacrificing environmental objectives, and this is an essential part of the puzzle. All right. The next page is just the track record of this in the U.S. We've lowered CO2 emissions in the U.S. since 2007 over the last 15 years, while our GDP grew by 45% over that same period. And you see the cause on the left, the salmon part of that. Again, salmon is our favorite natural gas color. The salmon part of that shows you how much gas expanded and the black charts -- the black bar show you how much coal declined over that period. And so the 24% decline, the 1.4 billion metric tons of CO2 equivalent emissions reductions that took place in the energy sector, 40% of that -- I'm sorry, 1 billion metric tons of that was coming from the power sector, which were down by 40%, okay? So we can do this elsewhere in the world. And if you look at the next page, this is an attempt to get at that. We can use more natural gas than coal. And between the combination of the 20 to 50 net change between gas and coal and the next bar over the 18% of additional CO2 reductions that we can accomplish by more aggressively replacing natural gas with coal for an overall potential net reduction of 24%. So natural gas can help decarbonize the world's energy while still making reliable and affordable energy available the world's people. Okay. This is more on the point of what we care about, which is how much people demand for what we do, our ability to respond to variability using our storage assets and showing up, making the commodity show up with firm transportation. On the left, you see just the filling and the drawing of storage. And you see that in big weather events, the draw on storage can be 40 to 50 Bcf a day. So you think of a total energy market of just a little under 100 Bcf a day in the United States. And we have come -- we recently came close to 150 Bcf, okay? So that's the big poll. The big gap filler is storage. We've been at 150 Bcf, I think, back in the polar vortex in the middle of last decade. But anyway, that's what you need. And so how are you going to get that? How are you going to replace storage, energy storage, which everybody knows is a part of the solution here? So we translated into terawatts just because we didn't have enough units to throw at people, we use terawatts here because you got to translate it into power terms, 6 terawatts of natural gas to get you that 50 Bcf. Even under the sustainable development scenario, we end up with 1 terawatt of battery storage. The other thing to keep in mind there is that, as I showed you, in response to Uri, we were on full withdrawal on our storage all week, okay? There was no time to reload it until we got to the end, and we were in 60-degree weather, and we could go on max injection, which is exactly what happened. It flipped around. So in order to even get that 1 terawatt, you have to be able to recharge. The duration on these things is 4 hours at best. You're going to get better than that. You're going to have to install even more battery banks in order to expand that capability. So I mean, I think these are just important energy realities, but it also tells you something about the value of our assets. Everybody agrees, that I know of, that energy storage is going to be an increasing part of this picture. We've got it. We've got it. And we've got it in an effective long duration basis, and we don't need any new technology to get it or new mines. We also have an attractive potential for handling liquid biofuels. On the numbers columns on the right, the first 2 are our Terminals and Products business segments. And then you see total U.S. production in the far right column. So we've got room to grow in what we already do. And increasingly, we handle a lot of ethanol today. We're growing our -- we handle biodiesel. We're growing our presence in both our products, business unit as well as our terminals business unit to handle renewable diesel. The difference between the 3 lines there, the bottom line is the stated policies scenario. So this is what governments have already said and legislated that they're going to do. On top of that is announced pledges. The big difference there being people who have, on top of what they've legislated, said, well, we have a net zero target in 2050. So that's what you get from that line. And then the top line is the sustainable development scenario. So using our existing assets in the transition, again, another theme of this whole discussion here to deal with the new fuels of the future. Okay. Next page, we talk about our ESG strategy. And here, we are pivoting our investments in the low carbon future. Natural gas and our renewable natural gas and other renewable diesel and other investments is now about 69% of our backlog. So you can see, that's our future, right? You can see the capital that's going into those businesses is pivoting toward that. We have been, for decades, doing carbon capture use and sequestration. And as that becomes increasingly economic, and that's an important part of the solution as well, it's something Jesse and his team already have the capability to do. We've been doing it for decades. And then just on our -- and we've started the Energy Transition Ventures group. And just on our own operations, continuing to be good at reducing our emissions and the environmental impact of our operations. On the social side, it's about maintaining good relationships with our stakeholders, broadly. It's about making folks, including ourselves, comply with our codes of conduct. And then on governance, I think we do an extremely good job there. If you look specifically on the G in ESG, we do very well there. If you think about how that part of the governance is pivoting toward the future, we've established an ESG committee. It's been in place for a long time, and we've done our reporting. And our Board is actively involved in that review and that process. On the next page, other practical things that we're doing that make sense for our shareholders and that makes sense for the environment. We have about 100 vapor combustion units in operations. If you think about a tank farm and you think about fugitive emissions, even with floating roofs and other things that are designed to minimize those, you're going to have some fugitive emissions. In many cases today, our facilities and others, those things are combusted and the combustion creates CO2, and it doesn't completely eliminate the emissions. The combustion is being complete. Well, if you go from combustion to capture, then you capture a valuable product and you earn money for that, that will pay for the capital that you invest. And here, we have a $64 million project in John Schlosser's business unit at Galena Park and Pasadena, $64 million having in service by the third quarter of next year at a 7.1x EBITDA multiple. We got more ground to cover there. As I mentioned, we've got about 100 of these in operations today. And there, you see something that puts it in context for you about the emissions reductions that would be equivalent to over 6,000 homes use of electricity for 1 year. On the next page. For us to be credible as a segment -- a sector in natural gas, continuing to play a powerful long-term role, we have to be good at fugitive methane emissions reductions. And many companies have come together in a concerted effort to be good at that. It's something that we've worked on since the '90s around here. We get paid to move the stuff not to lose it. And so there's always been a compelling economic incentive for us to reduce fugitive methane emissions, which are more powerful than CO2 by a factor of -- depending on the time frame you look at, but a factor of high 20s times. So when we joined one future when it was formed across the whole sector, production, transportation and storage, we were at 1.44%. Set a target by 2025 of getting to 1%. We're at 0.42%. Met that target early as a collective. The allocation of that 1% was 0.3% to our sector, transportation and storage. And we run, depending on the year between 0.02% and 0.04%. So beating by a factor of 10, the target that we have. And now this has become a marketable product for us. This is going to be key, I think, for our whole industry to do an increasingly good job at this. And you see in the very bottom right section there, we have 50 members today, which represent significant amounts of the production, 19% of natural gas production, over half of the pipeline mileage and a little less than half on storage. If you go to the next page, you see again the potential. Now this isn't all qualifying as a responsibly sourced gas or low emissions gas, but you can see that the people who are working on it account for a significant piece and a growing piece of gas production in this country. If you think again, it's a little bit under 100 Bcf a day market, we're growing into a significant -- this is growing into a significant piece. So we're -- we've done several transactions now, responsibly sourced gas where we team up with a producer to provide to our customer a low methane emissions product. It's increasingly important to our LNG customers that we provide this kind of service. It's important to utilities. It's important to a lot of people. We're going to keep making progress here. We've made a filing to establish paper pooling points on our Tennessee Gas Pipeline system to facilitate more people transacting in this. So this is now a marketable product. It's emerging and fast. It's accelerating. So to be in the business we're in, you have to be good at ESG, and this is about managing the risk associated with ESG. Six agencies have now given us a very high ranking, including in the top 10 in many of them. And we're now handled by -- we're owned by ESG -- funds with ESG mandates. It's gone up by 3x over the last 4 years. So it's important, and we are proud of being good at ESG in our business. It's important for us in building stuff. It's important to our coworkers. It's important to our regulators. It's important to our customers. And the team who's well represented here today has done a great job on this as has the whole organization, because this takes everybody. This takes all the operations team and everyone to make this happen. So we are positioned well for the future of energy. The keys for us are we got to do our existing business well. We gradually pivot as energy uses gradually pivot over time. And we have to be strong on ESG. And if we do these things and continue to improve, we can meet the twin objectives of preserving the climate, not cooking ourselves while still feeding ourselves, okay? And that's the objective, both of those things that we need to serve over the long term. So that's the broad context in which we're operating. We're going to go into the next section now on strategy and a little bit more detailed review of the business. And Kim is out sick today. She's going to be fine. She'll be back soon, but I'll cover her part for today. So here are the volume numbers again. We're moving up from here. On natural gas, in particular, 2022 is now -- is above the pre-pandemic level. Crude production is still not quite there. It is still recovering. But again, it improves from here. So the picture for the stuff that we move in store is improving from where we stand today. And the volume recovery is still playing out on assets -- on our assets here. So you see our refined products segment volumes on the left. And I'll focus you kind of in the bullets at the bottom on the left-hand side here because I think the useful perspective here is to think about where we are versus pre-pandemic or where we are versus 2019. And so our refined products, we're down about 7% overall. That's made up of road fuels being down 2% since pre-pandemic levels. So pretty -- getting back to very close to normal there, with jet fuel being down 27%. Now this is -- as you know, I mean, it's a function of less air travel. And also, the airports we serve in significant quantities are SFO, LAX, Atlanta Hartsfield, Dulles. I mean, those are -- there's significant international travel through those locations, and that is slower to recover than the domestic travel. So it will come back. It is coming back on the road fuels for sure. And then also, we've been seeing some nice improvement on the right-hand side in our G&P volumes. And so there, the sequential improvement from Q3 to Q4 overall is 7%. The Haynesville is 19%. That's a dry gas basin, and that's a sequential improvement in the quarter. It's a great asset for us to be seeing this growth in because we have a big system there that can move approaching 2 Bcf that's operating well less than that. And so it's a very capital-efficient expansion for us. Still got to hook up wells. We still need to add incremental treating facilities, that kind of thing. But it's a fairly low CapEx way to ride that wave up. The Bakken is also up 9% sequentially and then 6% kind of miscellaneous. So we're seeing good growth in our biggest -- our bigger systems, the Haynesville and the Bakken. Our strategy. So strategy, really, is about the key strategic choices that we make. And I think that's things like what sector are we in, how are we capitalized, what's our investment philosophy and our investment criteria, what's our commercial strategy, how do we contract our assets, et cetera, all to the end of enhancing shareholder value by maintaining a strong balance sheet, getting attractive returns on the money that we deploy, getting dividend growth with a well-covered dividend and then share repurchases with the excess cash. And so we've invested in stable fee-based assets that are core to the nation's infrastructure. I'll get into a minute on how those are contracted out. We've invested in low-carbon future in our natural gas business as well as adding to that portfolio, both in liquids fuels as well as renewable natural gas. We've maintained good financial flexibility. We're entering the year, expecting a 4.3 debt-to-EBITDA strong balance sheet that gives us some capacity for opportunities along the way, including share repurchases. So well inside of our 4.5% long-term outlook. We do have a low cost of capital. But on our capital allocation, we invest in a very disciplined way. We don't chase hockey sticks, as Rich mentioned, and we look for our investments to have an unlevered after-tax that well clears, well clears our weighted average cost of capital. That allows a margin for error when you have a delay or have an overrun or some other issue. So again, very disciplined in how we allocate capital. Going to the next page, how we executed on that strategy if you look at our performance in 2021. So zigzag a little bit back and forth here. In February, I mentioned the winter storm and how that demonstrated not just in Texas. This is true elsewhere on our natural gas network. Demonstrated the value of having storage, having that flexible delivery service, having firm transportation to get it there. And so revealed and executed well commercially on our flexible storage assets. In March, we announced our first responsibly sourced gas deal, and we formed our Energy Transition Ventures group. And as I think I said on one of the calls, I'm not expecting a lot, except a lot of reading and sorting for a while, but they came up with their first transaction fairly quickly. In July, we purchased the Stagecoach asset, a storage asset, a flexible storage asset. If you do just a simple arithmetic on it, it's a 3x kind of withdrawal to injection. Three-turn storage right in the middle of our TGP system in a part of the country where it's difficult to get new stuff built. So very happy about this, a bit above our acquisition model, and I think we're going to do very well with this asset. Then in August, our Energy Transition Ventures group came forward with the acquisition of Kinetrex for $310 million and $146 million in development capital, and that team is also performing better than the acquisition model. Then in September, the Liquids team got into the act, and we did a $65 million. We sanctioned a $65 million renewable diesel feedstock storage supply project. And so that was on the terminal side. That was for NESTE. So we ended up on kind of both sides of this. We have the hub that we formed on John's team in our Lower River assets. And then moving over to October, we sanctioned a project in our refined products business unit. So Dax and his team are building hubs in North and hopefully get under contract in the South as well to handle the renewable diesel at the other end. All of this illustrates again the theme that I keep pounding on, which is what we do today is valuable, and it's going to increase in value in key areas and can be pivoted to deal with the new energy commodities in the future. Okay. Here's how we have commercially proceeded. We seek to get our assets under contract for long term and with take or pay, meaning that people are paying for the capacity and they have a call on it, and they can use it or not use it. But we get paid in any case. So 63% of our cash flow is take-or-pay. 25% is fee-based, meaning also independent of the underlying commodity price. And then what is commodity price dependent, 6% hedged if you add that into that. So you have 94% of our cash flows that are secured by take-or-pay contracts, fee-based contracts or where the commodity price exposure is hedged. And I'll just point out, gas and products have G&P businesses. You put them together, it's about 7% in total of the overall segment cash flows. And then -- and this was more a bigger focus maybe a couple of years ago when we were very worried about credit. We always worry about credit. It's still the first thing we talk about in the Monday meeting. But the position -- the situation has stabilized for many of our customers. But on the left, what you see is that we're contracting largely with people who need our stuff, right? They need it directly. They're not just trading around it, right? There are refiners or there are power plants or there are utilities or there are producers who need what we do in order to get their stuff out or get the stuff in that they need. And then on the right-hand side, very strong credit with 78% that are investment grade or have substantial credit support behind it. So both of these things help further support reliable cash flows from our business. So we contract with people who need it most. We keep a sharp eye on credit as always, but that picture has improved. Now how about how we've invested the capital? Investing wisely in businesses we know at returns that are well above our weighted average cost of capital, in fact, significantly above our weighted average cost of capital. Here, on the right, you see our track record over the 3-year period 2019 to 2021. And what you see on the left is total capital invested. And we did this because all these projects are different, and they have different IRRs and different assumptions. In order to try to normalize all this, we expressed it as a multiple of year 2 EBITDA. Because by that time, you've got the project fully up and running. If there's a step-up or phase in to the customers' need, that's pretty fully reflected at that point. So $4.5 billion in capital invested on an assumed 5.8 multiple, and we ended up achieving 5.3x. About 90% of that was in the natural gas sector, and you see that on the right-hand side, bottom right-hand corner. And there, we ended up with 5.4x. So attractive multiples, better than target. About 90% of this is focused on gas over this period. We do get better returns just building off of our footprint and the execution risk is lower. And David will talk to you a little bit about the composition of our capital budget for 2022, but you're going to see that theme continue. All right. The business mix. Our sector choice, of course, is U.S.-focused midstream across a number of essential energy commodities and the markets that they serve. Our segment EBDA is broken down predominantly by natural gas, just like natural gas kind of dominates the backlog as well. Segment EBDA, 62% gas, 16% Products Pipeline group, 13% Terminals. If you put those 2 together at 29%, that's not all refined products, but it's predominantly refined products there. There's crude gathering. There's bulk terminal activities there as well, but it's predominantly that. And then we have about 7% that's in the enhanced oil recovery business, our current composition. Okay. Focusing in on the segments, in particular the biggest natural gas network in the United States and importantly, the largest storage position as well at 7 Bcf. That includes -- that is owned and operated storage at 700 Bcf. And you see from the line chart here, it's predominantly in transmission. There's gathering and processing there, too. But it's predominantly in transmission, and that business has been -- the throughput on that business has been growing over time, which bodes well over the long term for capacity contracting. Again, we're less focused on -- we're less paid by throughput than we are by just getting capacity under contract, but it's still a sign of the long-term demand for those assets. And if you look at the map on the right, you can see and just think about export points for a minute, export points in Texas and in Louisiana and into Mexico. And you can see our assets are extremely well positioned there. We have nice market shares for the part of that business that is growing. So this is the growth projection from now to 2030. So this is a 2030 timeframe and where it's coming from. And additional 21 Bcf coming from these basins on the upper left here. Permian, where we don't really have a G&P position. We have a substantial transmission, takeaway position. Haynesville, where we have a significant G&P position in the Northeast, which again is where we have substantial transmission and storage takeaway capability. Overall, demand, the increase in 15 Bcf over this period, you can see it's dominated by 2 things: Industrial at 5 Bcf and LNG at 9. And I think importantly for -- there's a lot of noise around permitting in this sector and getting 7c certificates and the like. Very importantly, as you note on the right-hand side, 95% of the growth that's forecasted between now and 2030 is coming from Texas and Louisiana, which are energy states, which have a tried and true process for certificating energy infrastructure and U.S. or in Texas. After the last legislative session, we even have more clarity around things like imminent domain. So it's a good place for this market to be growing if you want to continue to get things done. Next, LNG facilities. So we've got about a 50% market share right now on LNG, and we are in active discussions with about 2.6 Bcf of additional capacity on our system to serve LNG. We give our customers a lot of supply diversity. We give them a lot of good information on ESG and a good record on ESG. And the other thing we do is we focus very hard in our operations on getting them what they need, making sure they get what they need from a pressure standpoint, a gas quality standpoint, et cetera. Our operations people link up to make sure that we give our customers that level of service. And so overall, this part of the business, serving these markets is about 10% of the natural gas EBDA. And it's a market that continues to grow and that we continue to focus on and perform well for. Another key export market is Mexico. Now here, our share has come down a little bit. We still have a significant share, but with the -- in service of a couple of new pipelines, our share has dropped, but we still have significant opportunity. And the market is going to continue to grow. The trajectory really is demand for natural gas in Mexico continuing to grow, and supply continued to decline as they focus more on oil than they do on natural gas. And also, there's very little storage capability in the Mexican market, and we bring our significant storage resources, particularly on the Texas Intrastate. We bring that to the border and provide that service at the border. So again, this is a good historical market for us even beyond the throughput numbers is what we can do for them on providing the flexibility that they need in order to meet variable demand, particularly in their power sector. Okay. The other big piece of the puzzle here is industrial demand, 5.2 Bcf by 2030, 2/3 of that in Texas and Louisiana. And again, this is up into the right movement for this use of natural gas and by association, our infrastructure as well. A lot of this is on our Texas Intrastate system, where we are the last mile into these facilities. Now a lot of these guys have choices. They have more than one pipe connect, but we have the last mile into many of these facilities. And so we can provide them services, either bundled or unbundled, as they choose and having the big storage position that we do in Texas, and the transportation network that we've continued to expand makes us a good provider for that sector. All right. Products. These pipelines are the cheapest and safest way to move these essential commodities to markets that will continue to need them for a very long time to come. So 9,500 miles, 2.3 million barrels a day. It's the biggest refined products pipeline network. We also have in this business 65 terminal locations and approximately 16, which includes 39 million barrels of capacity in the terminal locations that we operate here, but also another 16 million barrels associated with the pipeline itself, the pipeline operations themselves. And so on the right-hand side, you see both crude on the far right, our Bakken and Eagle Ford positions, but then you see the makeup of our refined products deliveries as well. So dominated by gasoline, of course, but also diesel and jet fuel. Steady contributor over time. The pandemic notched it a bit. But as we get back to normal and particularly get back to normal and air travel and the like, it will continue to be a steady contributor and important. So it's an unmatched network. It's well positioned for renewable diesel, as I mentioned, but also the commercial structure here is an attractive one. If you look on the right-hand side there, we have EBDA growth that exceeds volume growth. And the reason for that is being very careful about our costs and getting an escalator into -- that's built into our tariffs. We'll talk a little bit about that more later when we have the business unit presidents up here. But anyway, that's a very attractive commercial and economic aspect of this network. And growth opportunities. So we have 2 hubs that Dax and the team are developing. One that's under contract at our Bradshaw facility in North Texas. We're working hard and feel pretty good about getting 1 hub in the South as well. So this is -- there's substantial credits, over $4 a gallon for this stuff in California. And so there's a powerful incentive to do it. Refineries are converting to renewable diesel rather than -- they're just converting to renewable diesel. So this is a good, growing market. We can handle it. We can handle it in our pipes and tanks, just like we can, refinery grade diesel. It's nearly identical chemically, et cetera. So this is a good opportunity for us. The Bradshaw opportunity is about $44 million. We think we've got another South opportunity of another $28 million. And the other key thing about this is the way Dax and the team have approached this is similar to John that we'll get to in a minute on the NESTE deal is make the hub. Make the place where people want to be with this stuff, get it into pipelines, get it into rail, whatever. Make the hub, and then hang other business on it as you're able to develop it. So good strategy for us here, a nice position and pivoting to the energy fuels of the future without sacrificing return. Terminals segment overview. Largest independent terminal network, 135 million barrels of capacity. Predominantly refined products, predominantly liquids and in turn, predominantly refined products. And -- but also, renewable fuels, we have -- we serve a lot of the ethanol market here, and we also serve the chemical market here. So very good. We kind of have -- we have a number of key hub locations. We'll talk about Houston in particular, but we have hub locations. We have good bulk terminal storage facilities. And then we have what we think of as rack locations. Those are the places with the tanks and the truck racks that serve a local market. And so that's the distribution in the map across here. And then we have a large and new Jones Act vessel fleet and seeing some nice turn in the outlook for that market as well. This is an example of how the team has approached it. John and the team have increasingly focused on building our hub locations. And this is, of course, the star example. This is the Houston Ship Channel adjacent to the best set of refineries on the planet. And you look at all of the connectivity. I mean this is a midstream asset. It's not just tanks. It's not just a pot to put something in for a contango play. This is an integrated midstream network that pull stuff off of refineries, sends it outbound by pipe, sends it outbound by rail, sends it outbound by vessel, and we've got spare capacity there to do more of that. Does blending operations for our customers and attract fees for that as well. And you can see that it's also interconnected. 16 cross-channel pipelines. So barge docks, ship docks, inbound pipes, outbound pipes connected to the best refining complex and bringing those refined products to the world across our ship docks. $2 billion invested in here over the decade. So this is on the export market. Because we're serving the leading refineries, we're well positioned to serve a global market, and we have room to grow. So if you look at the lower left there, you see that from this facility, Latin America, which is going to continue to need refined products for a long time to come, is our primary outlet for this product -- for our refined products exports. And then you can also see on the right-hand side, we're using about half of the capacity that we have. So there is room to grow this. And particularly, as global markets recovery, which you're seeing that recovery from the COVID trough starting to take place, we've got lots of headroom to sell additional services there. So nicely positioned for growth here. And here's the hub on the other side, on the feedstock side. So the Terminals group has a significant position in the Lower River, and we've been handling crude oils there for a long time. Well, now that becomes a hub for renewable diesel feedstock. And so we announced the deal with NESTE. We're going to invest about $65 million to create the capacity, and that's capacity that we can expand further. We've got an existing network. We've got dock access and -- both inbound and outbound. And so we can build this business and attract other customers into it. Once you get an anchor like that, then the expectation would be we'll attract other players into that market and the people who are buying and selling. The merchants will come to that market as well. So again, just like we talked about on the renewable diesel side, build the hub and bring other people in. And again, we're doing this at attractive returns. The CO2 segment. 9.2 billion barrels of original oil in place, and we keep finding -- Jesse and the team keep finding more ways to get it out. We have CO2 fields with 37 Tcf of original gas in place that we can use for a long time to come. We won't need to expand for quite a while as our current expectation. And then 1,500 miles of CO2 pipelines with the ability to move [ 1.5 bcfd ]. And these pipelines are specialized. To move CO2, you want to move it in a liquid state or supercritical state. That's 2,000 psi. That's not -- that's not what most legacy pipelines around the United States are capable of. For a transmission level, it's more like 600 to 1,440 for the more recent builds. And so these are specialized pipes, which has implications for CCUS, which we'll get into in a minute. But we have the potential to capture CCUS and put it into an existing pipeline network and use it to either to get oil out of the ground or to sequester it. So this is shining a little bit of a different perspective on this business than maybe we historically or it was historically thought of. In terms of how it performs, very low cost, $20 a barrel to get the oil out of the ground with our CO2 business. We use the cash costs. And it's been a consistent generator of free cash flow after CapEx. And so we're producing $400 million to $500 million a year over this period in free cash flow after our CapEx. So a good contributor from our existing business. Energy Transition Ventures. You see the time frames that we -- these are the things we're looking at right now, in the circle on the left, RNG, of course, and we've got some runway there. Renewable diesel, renewable power, maybe at our facilities, but also certainly backstopping it with natural gas deliverability. Carbon capture and sequestration, we need a little more clarity there on what the value of it is actually going to be. People are a little bit standing now, waiting for things to shake their way through on the 45Q. And then hydrogen is longer out. There are technical barriers there. But the way we're approaching this business is really 2 channels, if you will. One is that things like renewable diesel, renewable backstop, ultimately, hydrogen, those are things we'll be looking at in the business unit as things that we can do with assets that we have today. But then there are things that are step out from that but still within our camp, within our expertise and our capability, and those are things like CCUS and renewable natural gas. And so that's the way we've sliced it. The Energy Transition Ventures group doing the latter and the existing business segments working on the former. So the Kinetrex acquisition, $310 million with a backlog of projects that are being built out. Things are going well on the project build out right now. By the time we get those things built out, the investment multiple by 2023 will be under 6x. So good business for us. And on the right-hand side, you can see this growing by a factor of 10x, meaning the renewable natural gas participation in the natural gas business growing by a factor of 10x over the period shown here, which is out to 2050. And a lot of that value, of course, in renewable natural gas is in the RINs, the renewable identification number. And so just a quick note on that. So these are D3 RINs, and so there's -- associated with cellulosic biofuels. It's a relatively small part of the overall renewable liquid fuel mix. So it's nothing like it's going to be over 700 million barrels is the renewable -- gallons, sorry, 700 million gallons is the RVO for D3 RINs compared to billions, over 10 billion gallons in ethanol. So this is a relatively small piece. That's good for a couple of reasons. I mean, one is there's certainly room to go. We're well under the statutory requirement, and so there's a lot of room to grow. As the supply becomes more available to grow, that renewable volume obligation along with it. That's helpful. Because it's small, it's not as politically controversial and it has undeniable environmental benefits. And so it's not something -- it's bipartisan. It's not something that attracts a lot of opposition. Everybody understands the need to do this. It's the right thing to do rather than combusting the methane from the landfill. Capture it and sell it. It's undeniably beneficial from an environmental standpoint. And it also doesn't get caught up in the fuel versus food debate that ethanol does. And so all of that is good. The legislation is supportive. Again, we're well under what the statute specifies and the EPA does have some discretion in how to set that minimum, but it's really about making sure that they match it with the available supply. So that's good. And then there's also kind of some bumpers on their discretion, which is good and suggests good long-term value here. However, we are exploring. The other good news here is that in addition to -- we conservatively modeled our RINs when we did the acquisition, et cetera, and the RINs do have some fundamental underlying support, if you will. There is growing interest in this, in the voluntary market. So you think of the RINs market as being -- we're going to be replacing things in the refined products. In the transportation market, we're going to be replacing, say, CNG for electrification, let's say. So that's the transport market. In the voluntary market, these are folks who are trying to -- and there are many of them, trying to meet a net zero target. European companies with U.S. operations that want to make a net zero commitment. So the voluntary market is growing, and that's an opportunity for us to fix the price for the gas that we sell, to lock in the value for the gas that we sell, lock in the RINs, what would otherwise be the RINs component to give us an attractive return. Again, attractive returns in this foray into a new business that we understand well and we can handle. Okay. On carbon capture and sequestration, challenges remain, but this is going to have to be part of the solution for the reasons I talked about earlier. Key topics here, what's the final value going to be on the 45Q. We are engaged in actual real counterparty, real project conversations, but people are kind of watching and waiting to see how 45Q shakes out. It's some version of build back better that enhances it further, something like that. Injection well permitting is a challenge here. The Class 6 process takes 5 years, and that's going to have to speed up. Texas Railroad Commission is seeking primacy to be able to make those permit decisions here. That will speed it up. I think the EPA is plenty motivated to speed it up. There are only a handful of these out there or pending right now. That's got to speed up. And then the pipe requirements. As I mentioned, you've got to build some purpose-built pipe. By our calculations, if you short-haul smaller volumes, so less than 100 miles, less than 350 a day, then you can make existing pipe work for that because you're not going to try to pressure it up to 2,000 psi. But generally speaking, if you want to take a significant hub of emissions and take it to a sequestration location, you're going to need purpose-built pipe, which means you're going to have to have imminent domain, you're going to have to have permitting and you're going to have to have thick-walled steel that can handle 2,000 psi. So those are -- this is still going to have to happen in order to meet climate objectives. It's just that we're going to have to bust through a few barriers as an industry and as a country in order to get there. But all of this ties ultimately together, the hydrocarbon story and the renewable energy story together. The continued use of affordable and reliable energy is going to have to have this as a component. And so again, we have the expertise to do this. We can do this in other places, but we don't have anything to talk about there right now, okay? Other than that, this has promise, and we've got some capability and some expertise here. We have some live conversations going on, but this is still going to be a little while. So conclusion, again, ending where Rich started, this is a compelling investment opportunity. We've secured our cash flows. We've got a good yield with a healthy coverage on that dividend. Top 10, #6, the S&P 500, self-funding our cash flow, repurchase capacity, as we talked about, in a highly aligned management. All right. And with that, are we going to a break now? Okay. A break until 9:30, and then we'll come back into our business unit President and COO panel. [Break]

All right. Welcome back, everybody. And so as we did a couple of years ago, we're going to do a panel with our business unit Presidents and COO. And so I'll introduce everybody. I just want to make note for you. I've got some questions that I'm going to start with, and I'll go through several of those. And then we will be looking for the questions that you all submit. You should have all gotten an e-mail this morning with login information to MeetMAX portal, M-E-E-T MAX portal, and it will tell you how to log in and then and get a question in. However, if any of you are having any trouble with that or anything, you can come over, our IR team is here and they can help make sure that you get it in. All right. Very good. Well, first, introductions. So James Holland is our Chief Operating Officer; Tom Martin, the President of our Gas Group; Dax Sanders, the President of Products Pipeline Group; John Schlosser, President of the Terminals organization; Jesse Arenivas, who's the President of our CO2 business and also the President of our Energy Transition Ventures business that I referred to; and Anthony Ashley, who many of you know, who is the Vice President of Energy Transition Ventures. So we'll certainly take your questions. And as I said, I'll start off with a few.

And so first question that I have is for you, James, and it's about we're a year now into the operational efficiency and effective initiative. And so is it bearing fruit from a cost standpoint? And what do you think about improving our effectiveness overall in those functions?

Yes. I mean we've already talked about the financial benefit of the centralization effort. But a year into it now, we can see where -- when you look at it from a project execution standpoint, 30% of our project managers, engineering group have worked on projects that are outside of what their historic business unit would have been. And this year, we're expecting that number to grow to over 50%. So you can see going forward, we'll be able to deploy those assets where they're needed. But most importantly, it creates an opportunity for those employees to get experiences that they wouldn't have before and to get exposure. So from a project execution point of view, I mean, it's going quite, quite well. Then when you also look at it and as far as our agency interactions with our permitting group, in particular, as we regionalize that work, the agencies are now seeing the same people come to them for permit applications over and over regardless of the project. And so we're building momentum with those agencies because, as you know, if you can't get the permit, then you can't build it or you can't change it, right? And so our constantly building that momentum is starting to pay dividends as well. But one of the things that we did really over the last year was we converted our annual emissions reporting to a monthly process. And that was a big hurdle, but what that does is it really sets us up so that going forward, our ESG reporting can now start to be really in line with our financial reporting as well. So I think we've just scratched the surface. There's a lot more to go, but a year into it. I mean a lot of progress.

Very good, very good. So we hit the financial and efficiency benefits that we meant to, and we're seeing the benefit of bringing those organizations together. And the big focus there was not losing accountability and responsiveness to the business units, and that takes everybody here working together to make sure that happens. Next thing is natural gas. Tom, can you discuss natural gas storage values, what you're seeing today and what you think the opportunity is going to look like over the next few years?

So I mean we've definitely seen improved storage values. I think Winter Storm Uri had a lot to do with kind of getting the momentum going there. We have seen an increase in value and demand for multi-cycle services, whether they be traditional defer storage-type transactions or sort of bundled peaking services from many of our customers, particularly those in the power sectors as well as some of the LDC customers as well. But longer term, really 2 major factors determine the value of storage. If you think about the scale of the natural gas market as a whole today, about 100 Bcf a day growing to 120 Bcf a day by 2030. We're not really building or increasing, expanding the overall storage footprint in the U.S. And so the need for storage facilities to backstop supply disruptions and other matters, issues that occur in a growing overall market. I think that's certainly one supportive driver going forward. But then secondarily, and Steve touched a lot on this in his comments, as we see the migration of renewable penetration from the West Coast towards the East, we're seeing a significant need for incremental variable backstop storage demand from power customers as well as just the market in general. And so as we see that trend move from West to East, we think that increases the value for long-term storage going forward. And I think lastly, we're looking at opportunities to expand our capability. We really like our 700 Bcf storage position, and we think that increases the value over time.

All right. Very good. And switching now to products. A specific -- very specific question, Dax, how does FERC's recent ruling on our annual pipeline rate adjustment impact you compared to your 2022 budget?

Yes. So FERC last week ruled -- it had been a tolling situation for a period of time. The FERC at or was -- had been set at 0.78. It was changed last week and revised to be plus 0.78, revised to be minus 0.21. And as you know, the usual protocol that you file annually to put new rates into effect July 1. The additional thing about this ruling was it required people to restate the rates that they put into place last year effective March 1. So the -- again, the effect is you restate your rate starting March 1, for minus 0.21 versus the plus 0.78 and you file for the new rates this year using the minus 0.21. Now you all know we've obviously got a pretty high inflation environment. And again, that's an adjustment to PPI FG, which is running right now. I believe the number for 2021 was 8.74%. So effectively, it's 8.7 minus 0.21. That will be the new adjustment that goes in. So -- but if you take all of those components and look at where we are right now for 2022, based on how we budget, we actually have a little bit of upside. So I'd say something on the order of $1 million compared to what's in our plan. Again, and that's taken into account the retroactive filing for the rest of this year for the stub period between March and the middle of this year as well as the new filing for the end of the year.

All right. Very good. And John, you have significant dock capacity available in the Houston Ship Channel. What's your outlook there for exports? And is it an opportunity for upside?

Sure. Sean, could you flip to Slide 49? In general, as Steve mentioned earlier, we're very, very bullish on the refining [indiscernible] Houston and obviously, the prospects for exports going forward. This is the largest refining hub in the world. And our facility is the largest terminal there. It has unparalleled optionality, connectivity and liquidity. And I'm going to focus just on one of the numbers here, and that's the 31 inbound lines that Steve mentioned. That's connected to 10 of the most cost advantaged refineries in the world. They produce on aggregate 2.8 million barrels a day, which obviously puts us in a tremendous position. There will be some of the weaker players that will eventually be rationalized throughout the United States, but we personally believe that the Houston Ship Channel is going to be really the kind of the last man standing out there, which puts us in a tremendous position. The key to that, though, is being able to access both the domestic as well as the export markets. And in the face of potential declines in domestic consumption, we think that there's nobody better positioned than we are. WoodMac is estimating, as Steve alluded to, Latin American consumption growing slightly less than 2% a year all the way through 2035. We have -- right now, we had our best quarter ever in Q4 over those 11 docks that are mentioned there, best quarter ever. And yet we're only at about 50% utilization. So we have roughly 300,000 to 350,000 barrels a day of upside. And the key to that, though, is that there is absolutely no capital needed to handle those barrels. The assets are already in the ground, already operational and no dollars are needed to handle that additional capacity.

All right. And switching over to CO2. Jesse, you talked about the uncertainty of the timing on CCUS, but what is your competitive advantage in CCS, whenever it comes along?

So first of all, our company and our predecessors have been sequestering carbon for about 50 years. Second of all, we've invested in the past 20 years about $7 billion in CO2 handling and processing facilities, pipelines and EOR fields. So our industry-leading experience across the entire value chain puts us in a good spot. Further our unparalleled asset footprint in the Permian with the emissions of natural gas processing is about 300 to 400 million cubic feet a day puts us in the position to facilitate the growth in that market. So I think when you look at our competitive advantages, we've been securing carbon for a very, very long time. We have expertise in the design, construction and operations of CO2 processing facilities and pipes. And ultimately, we have the sequestration expertise in-house. So I feel like we are very well positioned to facilitate the growth in this space.

All right. Switching over to ETV. Anthony, similar question. We've indicated that we intend to grow the RNG business. What's our competitive advantage there?

Yes. So when we purchased back -- Kinetrex back in August, we really did it with a view that it was a platform-level investment. We were looking for a way to enter the market and scale up quickly. And Kinetrex was definitely an attractive opportunity for that. And we were -- currently, Kinetrex has on RNG facility and 3 under construction and Steve kind of went over that earlier. We really didn't get into the market just to own 4 facilities. We recognize that the market is fragmented. There's opportunities for consolidation as well. One of the many reasons we like the Kinetrex deal is the integrated business model. And so they have direct relationships and contracts with the end users on the transportation side. And also with the obligated parties who are responsible for monetizing the RINs value as well. And what that really means is they're able to keep a bigger piece of the value of the environmental attributes. And then if you add Kinder Morgan into the mix, we're not only just adding sort of a balance sheet. We have extensive customer relationships, pipeline and interconnect experience, which is a big piece of the economics here as well. Also, we at -- our KM Treating group, we can manufacture some of the equipment as well. We have a history of operational excellence that we bring to the table. And as a large company with a large procurement group, we can better navigate some of the supply chain issues that we're seeing today. So I think in summary that if you take a Kinder Morgan and Kinetrex together, we bring a lot of value to the table that smaller and less diverse companies could.

All right. Very good. And so we have questions coming in also from the people participating here. So first one, Michael Blum from Wells Fargo. Can you discuss your latest estimates for gas pipeline recontracting risk and what pipes are driving in remaining EBITDA declines?

Looks like we have a slide on that one, if you can bring that one up. But I think the good news is, and we've been covering this topic for many years. We're getting, I think, close to the finish line of all the major recontracting risk issues that we've talked about for the last several years. Really the remaining area or pocket of recontracting risk is in Copano South Texas on our Eagle Ford contracts that were multiyear contracts that are renewing in a different price environment. But as you look to 2024, we really are through all of that and look to be really kind of improving from there is the way I would think about it. So we've addressed all the issues on Ruby, FEP, MEP, several of our Rockies is used over the years. And so Copano South Texas is really the last one, and I think we have some green shoots kind of going forward from here.

All right. Very good. Next question is from Keith Stanley of Wolfe Research. For you, Dax. Crude pipeline volumes are budgeted to grow 13% in 2022. Can you give more detail on drivers here, Eagle Ford versus Bakken? And if you have any contract step-ups that are driving higher volumes on your systems?

Yes. So the driver really is our 2 largest crude assets are Hiland crude gathering and KMCC. And so the growth is really between those 2 assets. I'll start with the Bakken, which is probably the clearer of the 2. I think we did Hiland Crude there, we have largely acreage dedications, that type of arrangement with some of the key acreage up there and kind of the key areas. I think we did just over 200 -- roughly 250,000 barrels a day. In 2021, we're roughly 230,000 for this year. So that's the volume step up there. We've got -- we have continuous conversations with our producers up there. And we have pretty good visibility into the planned well counts. I mean we get really an update almost every week. We connected, last year, 96 wells behind our system. This year we're budgeted for, I believe, 183. And so -- and not all really -- I mean we've got a couple of -- we've got a small number of unidentified wells. But by and large, it's a predicate of continuous communication with our producers and them telling us exactly what their plans to do. I think the other kind of macro factors up there. If you look at growth in rigs and growth in completion crews that type of thing. It really all sort of substantiates what we've heard. In the Eagle Ford, on KMCC, again, I think we were just under 200,000 barrels. We are just over 220,000 this year, which again is kind of right in that range of the 13% you identified. The largest there -- we don't obviously connect well specifically, but we do have a lot of communication with our shippers, and we get a lot of information from them and market reconnaissance on what they're planning to do. We also have, as you know, a marketing affiliate that we stood up a couple of years ago that's doing that -- last year did roughly 50,000 barrels a day on KMCC. And that is -- and again, the capacity of KMCC is north of 300,000. And so we've got plenty of excess capacity there, but our marketing affiliate is able to go into South Texas buy barrels, ship them and make a very low-risk spread on that transaction and move volume. So I think we're pretty confident that between our shippers and our marketing affiliate, we'll get to that number on KMCC.

All right. Very good. So next question is for you, Anthony. From Elvira Scotto at RBC. How big can RNG become relative to the natural gas segment? And how will you approach M&A and RNG? So you might pull up the slide where we talked about the growth in RNG as part of the mix. But anyway, M&A and how big can this be?

Yes. So RNG, I think it's not going to be -- it's going to completely take over natural gas out anytime soon. I think you're -- looking at numbers there, which go out to kind of 2 Bcf a day, which are a pretty small component of where we see natural gas today. But there is tremendous growth in this segment. So it's not going to, as I say, replace the need for geologic natural gas. So there's a lot of interest. I talked about the market being a fragmented market right now. So there's lots of opportunities for consolidation. There's opportunities in terms of -- JV potential opportunities as well in this sector. So we see tremendous growth. We see our ability to grow this segment quite exponentially at this point in time. Where it goes, I can't necessarily say at this point in time, but there are significant opportunities that we're looking at today.

Okay. Next question is for John from Michael at Wells Fargo. Can you walk through the assumptions -- go to Slide 25. Can you walk through the assumptions behind the 7x multiple for the Galena Park and Pasadena terminal? How large is the investment opportunity set for these types of investments across your terminal portfolio?

Just for terminals, there's 42 additional VCUs that are within our network. Not all of them are in Houston. They're scattered all throughout the network. We actually sanctioned a small project at our Argo facility. And we have a full team that's looking at the additional 42 now to see what other opportunities are there? Where is the point of inflection? And where does it make sense to make these investments? So we think that there will be a number of them as we proceed here. But this is the biggest one that we were able to pull off, lowest-hanging fruit that we had. The rest of them will be onesies and twosies throughout the entire system.

All right. Next question is for Tom from Jeremy Tonet at JPMorgan. Given upcoming need for Permian gas takeaway, do you see a new gas pipeline build or conversion as more likely? How do higher steel prices impact the tariff needed for a new pipe? And how has this dynamic impacted commercial discussions? So new pipe or conversion and steel prices.

So I think more than likely, it will be a greenfield pipe. And yes I agree, there's certainly a need for incremental takeaway capacity out of the Permian, timing of that. We've talked about that on the quarter call. I mean, I think the market would like it sooner even than 2024, but I think realistically, from a project execution perspective, that's probably the soonest that it would be in service. And clearly, steel pricing and other inflationary factors are impacting the tariff on incremental projects and certainly, that would be a factor on that new project as well. Good discussions though with customers. We -- I think we have a good track record. We've proven that on 2 previous projects of execution. And so I think there's some really -- some good opportunities there for us to potentially consider doing another project maybe to go in service sometime in 2024.

All right. Next question is from Michael, Wells Fargo. And I'll take this one. Do you expect to set specific emissions reduction targets in the near term, such as 2030 or earlier? And do you expect to tie management compensation to metrics such as this? And so the answer to that is we've gone through the process now of measuring and reporting our Scope 1 and 2 emissions. That was part of our plan that we set 3 years ago. So it's been in the works for a while. And that's, of course, the first step is you've got to measure and know what you have and know where they're coming from, so that you can start to take action on them. And things like the project that John was talking about and other things that we've looked at doing through the organization, certainly, those things, how they affect our emissions is now a part of, for example, project review discussions in a way that it hasn't been historically. And so we think about what's the emission reduction we get for this in addition to what's the return benefit that we get. As you saw the analysis on the VCU to VRU conversions. Now we're not a believer as a company in setting a target that we don't precisely know how to meet. And so we have not come out with specific and don't currently expect to come out with a specific 2030 or 2050 target. I think there's a lot of information that you have to have. And we're also not as inclined perhaps to rely on actions of other parties to achieve those targets, meaning making a broad assumption, for example, that the entire electric consumption that we undertake will all be renewable power. I think that's a pretty tall order for the power grid to come up with. And so we're not going to write our check on their account, if you will. I think it's going to be important for us to see our own path forward. The other thing that is, I think, an important dimension, at least is how we think about this. As you saw from some of the new opportunities that we're pursuing here, we're looking for opportunities to help other people meet their targets, whether that's in renewable natural gas for people who are in the voluntary market, trying to get to a net 0 target or whether it's helping someone who captures their own CO2 to get it sequestered appropriately, which is what we know how to do. And so what we're focusing on is what can we do about our own emissions, but also what good work can we do to help other people meet their targets. But setting a target that I'm writing a check on a future CEO's account or writing a check on another industry's account is something that we're unlikely to do and think that is unwise to do. But we will continue to measure this stuff, look for opportunities to reduce it in our operations as well as helping other people reduce theirs. Okay. Next question is from Jeremy at JPMorgan. Let's see. It looks to me like this is going to be for you, Anthony, has or will KMI file for Class 6 will ask you and then, Jesse, if you have anything to add, has or will KMI file for Class 6 wells with the EPA. If filed with the EPA, can they be grandfathered or moved over to the Railroad Commission upon Texas gaining primacy? Or would the process start over again, how quickly do you think the Texas RRC could approve Class 6 wells? All right, give it a go.

Yes. I'll let Jesse chime in on this as well. But we are currently -- we currently have not filed for a Class 6 permit with EPA. There are a number of opportunities that we're working on down the road, which could be -- could result in Class 6 EPA filing. With regard to the Texas and the primacy there. What we've seen, and this is really seen on with regards to applications that have been going on in parallel with the primacy -- the application of Louisiana is the EPA has been kind of handling that in partnership with Louisiana. And so it wouldn't delay or really accelerate in any fashion, the process -- or delay the process. So you don't have to repeat the work, you have to -- that you've already done. So I would expect with Texas' filing with that you could -- again, you could do things -- do the applications in concert. And the EPA and Texas will work together, and the timing will be kind of TBD. In general, on Class 6, what we had seen traditionally is 5-plus years with regards to the time frame to get to our permit. I think we've just got one in North Dakota. The North Dakota has primacy right now that was permitted. And that took, even with just the state pharmacy, which is supposed to accelerate these matters that took probably 3 years in terms of development for the -- to get all of the materials together for the permit until they actually got permitted. So they're trying to accelerate the process, EPA is trying to accelerate the process, the states are trying to accelerate the process. But I think we all should be realistic that it's going to still take some time to get through what is a very sort of lengthy process. Jesse, got anything to add?

No, I think on the Class 6, you've nailed it. I think we're also exploring other avenues potentially using a Class II well that will greatly reduce the time necessary to inject CO2. It's going to be some limited applicability there. But -- so we're looking at all of our options. And to your point, I think the primacy will probably just supersede the EPA when that happens. So I think we're not real concerned about the conflict there.

Okay. So that's all the time we have. We are going to do a Q&A after David gets through his presentation. We're going to use the same platform here that we were using just now. So the folks that are in the queue that we didn't get to, feel free -- is it resubmit? Should they resubmit -- or no, it's fine. We'll just add you to the queue. Thank you. David? Thank you, guys.

All right. Before we get into the budget, we'll cover some historical performance for Kinder Morgan on Slide 61. So as you all know, Kinder Morgan focuses on cash flow. We generate a lot of it, and we've been generating an increasing amount of it over the years. On this slide, you can see that since 2016, we've increased our EBITDA by 9% when you exclude the assets that we've sold since 2016 from that starting point. We've generated CFFO 11% greater than what we generated in 2016. Our free cash flow is up over 80%. Our debt is down almost 20%, and we've more than doubled our dividends to our shareholders over this time. So in other words, we're generating meaningfully greater cash flow. We've substantially reduced our debt, and we're returning a much larger amount of our cash flow to our investors over this time. So I think as -- as Rich said, this really demonstrates that we are a company that's run for shareholders by shareholders. Slide 62 delves into -- dives into our free cash flow generation a little bit more by breaking it out by year. Between 2016 and 2021, we generated almost $30 billion of cash flow from operations. And after deducting the amount that we've invested in our capital expenditures, we generated free cash flow of about $15 billion and $11 billion of that went to our shareholders. On Slide 63, this is our published budget. This is consistent with the summary of the budget that we provided in December. It's just got a lot more detail on the following slides. And as usual, we've posted this to our website, and we'll be comparing back to it throughout the course of the year to keep ourselves accountable. So as the contribution from Winter Storm Uri in February of last year, was largely nonrecurring. Most of the variance comparisons that I'll be probably speaking to for 2021 exclude that contribution to put the 2 years on an equal footing. So in 2022, our budget has us generating net income of $2.5 billion, that's up $1.6 billion from last year. We expect to generate $7.2 billion of EBITDA, up 5% from last year. Our distributable cash flow is expected to be $4.7 billion, which is up 8%. We expect to generate discretionary -- excuse me, spend $1.3 billion on discretionary capital, and we expect to declare dividends of $1.11 per share, which is up 3% from last year. And finally, we expect to end the year at 4.3x adjusted -- net debt to adjusted EBITDA. This is going to be our seventh year in a row with no need to access the equity markets with operating cash flow more than covering all of our projected cash needs, including our dividends, sustaining and growth CapEx. And in fact, as we announced in December, we expect to generate cash flow in excess of dividends and all of our other cash needs of almost $900 million. And of that, up to $750 million, we expect to be available for incremental opportunities, including share repurchases. We don't have any buybacks assumed in the budget though. Slide 64 is our EBITDA bridge from '21 to '22. You can see on the left-hand side there, we've adjusted for the Uri contribution in 2021. Moving from left to right, you can see the first wedge there. We have some headwinds, some relatively minor headwinds from natural gas contract expirations and some rate risk in 2022 relative to '21. And then we have to the right of that multiple areas of growth expected for 2022. The first 3 categories are all base business growth driven by our CO2 segment with good price realizations expected for '22, our natural gas storage value realizations in our interstate -- intrastate business and then a category for other base business growth. That's largely our gathering and processing volume and price as well as refined product volume improvements this year. The right 2 categories, they are more externally driven. The first one is growth project contributions largely from our natural gas segment. Good returning projects that we've invested in. And the right hand -- the very last one is the full year contribution largely from our Stagecoach acquisition from last year. And that gets us to the $7.2 billion of EBITDA that we expect in 2022. Moving on to Slide 65, our assumptions and highlights for the year. This slide really just dives into a little bit more of the assumptions driving growth for each of our segments. I won't go through each one of these, but I would point out that when you exclude Uri, you can see each one of our segments is expected to grow in 2022. So nice to see across-the-board performance there. I'd also point out on interest expense, we have here our budgeted LIBOR is expected to be 56 basis points for the year. So that's lower than where the current forward curve is. So we'll keep an eye on it. But I'd point out that in 2021, we took advantage of lower forward LIBOR rates and locked in over 70% of our 2022 LIBOR exposure. So glad we did that, and our exposure there is pretty small. Slide 66. On the top of the table, you can see once again, our reconciliation from net income to DCF and the 2 main categories that comprise the most of that reconciliation are DCF includes cash taxes. It excludes book taxes, and it includes sustaining capital, and it excludes depreciation and amortization. So thinking about those, as I said, we focus on cash and DCF is really our best attempt at a cash proxy for earnings. And when you look at those reconciliations, I think that makes sense. Going to the bottom 2 rows of the bottom table, adjusted EPS. And adjusted EPS strips out certain items is $1.08 in our budget for '22. 2021 without Uri would have been $0.94. So we're up 15% on our adjusted EPS. DCF per share is expected to be $2.07, and that's versus $1.92 from last year. So we're up $0.15 or 8% year-over-year. Slide 67 is our adjusted EBITDA. And here, you can see that our natural gas pipeline and CO2 segments are down year-over-year. But again, that was colored by the contribution from Winter Storm Uri last year. Uri contributed $962 million to the natural gas segment and $138 million to our CO2 segment. So once again, if you exclude those, we're expected to grow across all of our segments in 2022. In our G&A and corporate charges category, we have lower costs of $43 million. We are expected to have higher capitalized costs, so more of those expenses are going into the capital bucket versus operating expenses. And we also have lower noncash pension expenses in 2022 relative to '21. So that brings us down to adjusted EBITDA. And going to the adjusted EBITDA, excluding Uri row, you'd see we expect to have $330 million or 5% better generation of EBITDA in '22. Interest expense is lower by $42 million, and that's mostly due to us continuing to refinance maturing debt with lower cost debt. We also have a little bit of lower overall net debt, both contributing to that lower $42 million. And on DCF, excluding Uri, we're budgeting to be $349 million better or 8% higher than 2021. In our December release, we said we were going to be 9% better. But at the time, our forecast didn't anticipate us finishing the year as strong as we did. So we're now 8% better because of a strong finish in 2021. All right. Moving on to CapEx. Sustaining capital is largely expected to be in line with 2021, but a couple of larger moving pieces there. First, in the natural gas segment, we had a onetime pipeline replacement project which was about $60 million last year that won't reoccur. So nat gas is down $36 million because that $60 million was partially offset by greater pipeline integrity spending that we expect to do in 2022. The product pipeline is also expected to spend more in sustaining capital by $49 million. That's also due to greater pipeline and integrity spending. Moving down to our discretionary capital. The larger projects here are listed to the right-hand side for your -- for those of you who are going to try to model some of this. And then pointing out a couple of things in the discretionary capital. In 2021, you can see natural gas had a $1.6 billion listed here, but that includes $1.2 billion of our acquisition of Stagecoach. So excluding that, nat gas spend is up $220 million. In that $220 million, nat gas includes $150 million contribution to SNG, which is our -- funding our share of SNG's maturing debt. That's pretty normal for us. We include our contributions to our subsidiaries that have maturing debt on a regular basis. It helps us tie to change in net debt. In the CO2 ETV or energy transition Ventures category, you can see the 2021 number of $362 million there. It includes $310 million for our Kinetrex acquisition. Without that spend, we'd be up $148 million as we continue to build out the additional RNG facilities that Anthony has talked about. So once again, all of our capital projects are relatively small. We only have 2 projects currently that we're spending money on that are greater than $100 million. So pretty small. And the nice thing about that is these projects have higher returns generally than the larger, higher-profile type projects that we've spent on in the past. In fact, across all of our full project backlog, if you exclude CO2, our EBITDA multiple is less than 3.5x. So very attractive returns. And then at the bottom of this table, we show the reconciliation from discretionary capital to GAAP CapEx as many of you focus on GAAP CapEx versus our non-GAAP discretionary capital. Slide 69 is our CFFO and free cash flow calculation. So this slide walks from net income down to cash flow from operations, or you can see our $5.3 billion of CFFO we expect to generate in the year. We deduct our GAAP CapEx to arrive at free cash flow of $3.4 billion and then further subtract out our dividends to arrive at the free cash flow after dividends number of almost $900 million. Slide 70 is our sources and uses. This is a high-level summary of our sources and uses for the year, just giving you a sense of some of the larger moving pieces for '22. So sources, there's a $5.3 billion of CFFO. We started the year with over $1.1 billion of cash on hand, and we expect to receive distributions from JVs that are captured in our cash flow from investing section of the cash flow statement of $130 million, which would leave us with $866 million of borrowing and/or debt issuance is needed for the year. And that's in order to fund our uses of $2.5 billion of dividends, $2.5 billion of debt maturities, funding of our $1.88 billion of CapEx and about $560 million of other cash uses. So once again, we don't have a great deal of need to access the capital markets. And as we'll talk about on the next page, we've got an undrawn $4 billion credit facility. So really good position, which is nice going into this year since the Fed is anticipated to hike rates multiple times. So going on to Slide 71. Expect to end the year, as I said before, at 4.3x, which is below our longer-term leverage target of about 4.5x. We're also in a very strong liquidity position with $3.9 billion of available capacity on our revolver. Started the year with over $1 billion of cash on hand and expect to generate the $900 million of free cash flow for the year. So a nice position there. The next page is our quarterly profile. This is really just for you to help calibrate models. Once again, our yearly results are not evenly distributed across the quarters. We have some seasonality in our natural gas pipeline business where winter demand for our services increase our utilization and rates. So our Q1 and Q4 are typically higher in that business. On our DCF, we also have lower -- traditionally, we have lower -- we're budgeting for '22 sustaining capital spend in the first quarter, and we have cash tax payments in the second quarter, which add to that seasonality. So again, we expect our first quarter and fourth quarter to be our highest generating quarters followed by our second and third. Moving on to our cash tax calculation. For those of you who really want to get into some modeling, we expect to generate a taxable loss for 2022 of $307 million for the year, and that's mostly driven by our tax depreciation. So Obviously, we don't expect to owe any federal cash taxes for the year, and this will add to our net operating loss balance that will shield us in future years. And at this point, we don't expect to be a federal cash taxpayer until beyond 2027. The $81 million of cash taxes that we do expect to spend in the year are represents our share of cash taxes due at 2 of our C corp -- or multiple, but mostly 2 of our C corp subsidiaries, Citrus and Products Southeast Pipeline. Slide 74 is our budget sensitivities slide, which is largely for your reference, but just pointing out a few of the things that are added in here. We have, just like last year, our sensitivity to natural gas gathering and processing volumes, our refined product volumes and crude and condensate volumes. Our exposure to crude oil price is $7.3 million for each $1 change in the price of a barrel of oil. And our natural gas exposure -- or exposure to or sensitivity to natural gas prices is even lower $400,000 for each $0.10 change in the price of gas. Let's see. Moving on to our financial highlights then. So to wrap up, we generated record cash flow, as you all have heard, record cash flow in 2021. And even when you exclude the contribution from Winter Storm Uri, we met our budget in '21. So nice performance. We increased our dividend in '21 by 3%. We reduced our net debt by over $800 million. We generated record free cash flow, and we continue to improve our cost of capital by issuing 10- and 30-year debt at coupon rates that were among the lowest in the company's history. And for '22, we expect another 3% increase in our declared dividends. We expect to further reduce our net debt by over $350 million, improve our leverage ratio to 4.3x and grow our DCF per share by 8%. We also -- as Steve has mentioned, we have $750 million available for additional opportunities to invest, including share repurchases. So outstanding performance in 2021, really strong expectations for '22. And that completes the budget section. So we'll now transition into the broader Q&A section. So I'll pass it back to Steve to kick us off.

Okay. All right. Thank you, David. All right. As I said, we're going to use the same approach that we did for the Q&A for the business unit panel. So log on to the MeetMax portal. Based on the information you got an e-mail earlier, and then I'll go through the questions. And our business unit Presidents should still be miked up, I hope, because the first question is going to go to Tom. So this is from Spiro Dounis at Credit Suisse. The question is, is there an appetite to expand your downstream LNG footprint with more liquefaction and export capabilities?

Can you hear me? Can you hear me now? There you go. Yes. So we -- as you know, we're fully operational now at Elba Island from an export LNG perspective, and there is an opportunity to potentially expand our capability there. It would be 2 small-scale trains, maybe 3 million tonnes a year opportunity. We talk to our customer there about a year ago about that. There really wasn't much traction at that time, certainly worth considering and getting some additional focus on that going forward. But nothing really imminent there, nothing worthy of really further discussion that -- other than there is opportunity there.

Okay. The next question is from Jean Salisbury from Sanford Bernstein and the question is, David, when will KMI become a full cash taxpayer? And did this speed up due to the first quarter of the all?

Yes. So...

Hold on, one moment. Okay.

Yes, a good question. We did generate...

A little Closer. Al little closer.

Okay. All right. Can you hear me now? All right. Great. So we did generate additional profit in 2021 as a result of Winter Storm Uri, but we also acquired Stagecoach and had some additional depreciation and attributes associated with that. So we put it all together, and we look out into the future on our taxable income and our depreciation associated with all of the expected spend. We don't expect to be a cash taxpayer until after 2027. So in the years past, we've said we don't -- didn't expect to be a cash taxpayer until after 2026. And largely just -- and it's a complex calculation, but largely because we just had greater visibility going out into '26 and '27. We are comfortable now saying that we won't be a federal cash taxpayer until after 2027.

Okay. The next question is from Brian Reynolds at UBS. So bear with me here. Given recent regulatory hurdles that we continue to see around greenfield low-carbon pipeline infrastructure and given that 70% approximately of KMI's capital backlog is in low-carbon investments, how is KMI looking ahead to address regulatory hurdles as it pivots to growth with renewables investments? How do you see the regulatory environment evolving and how is KMI getting ahead of the FERC and Army Corps to address future low-carbon infrastructure build-out concerns? Okay. So there's a lot in there. And certainly, it's the case that in really just about any context and energy permitting has gotten more complex. And so we've had to spend more time measuring twice and cutting once in order to be in a position to take advantage of that. So we start by as we're examining a project, really deeply examining what the permitting and regulatory requirements are going to do. We do a lot more advanced public outreach to agencies and other local officials and communities along the way. So a lot more -- there's a lot more upfront that goes on now in order to accomplish project permitting and community acceptance than was done in the past, for sure. That's the case on all things. And so now you have to slice it further and say, well, what are the distinctions between the different kinds of projects. As I mentioned, when we were going through the macroeconomic outlook for growth in natural gas and where that growth is coming from. A substantial share of it, 95%, is coming in the states of Texas and Louisiana. And so those are energy states that have been dealt with and cited and benefit from the expansion and addition of energy infrastructure. And so intrastate projects in those jurisdictions are going to tend to be shorter permitting processes, et cetera, than what you would see on a multistate interstate Seven Sea pipeline project. So that doesn't completely eliminate regulatory review, of course, there's state and local reviews. And there's also, as was referenced by the question -- by Brian's question, there's Army Corps reviews. An Army Corps, as we did under our PHP project, you proceed under a nationwide rule. Nationwide Rule 12 in the case of our particular kind of infrastructure. And I would say that process is still out there. I don't think you can count on it shortening, but you've got -- you go through that process and you go through consultation with the U.S. Fish and Wildlife to get that done. And on PHP, in particular, which had its challenges, we were able to go from FID to in-service in about 27 months. So that's one part of the picture. On interstate long-haul natural gas pipeline is to take a different to take a different slice at this. The 7c process is still being worked through. The commission is coming to terms with how they're going to account for greenhouse gas efficient on projects and whether that's just going to be what's produced by the project for downstream missions as well and how exactly do you calculate that. And that is still a bit uncertain. And so the answer to that is we don't know yet in terms of where they're going to come down. we're going to be constructive in that. We will propose our own ideas for what we think the carbon footprint is of the asset. In some cases, will be easier than others, where we're displacing coal, for example, on power plant-specific destination. I mean that's going to be easier than what happens if it's going in the global market, let's say. So you really have to get down into some of the finer details in order to unlock how it's going to work in each individual project. Tom, is there anything that you want to add to that?

Yes. I guess the other thing I would say is that it certainly adds more time into projects and maybe what we were thinking about for and especially on 7c projects. We've gravitated more towards what we call linear projects where the way we structure our contracts, we spend money more when we have certainty. And so that also I guess, lengthens the time of a particular project.

So if we could boil it all down into a short answer, it's very much case by case, but in each individual case that we're making this evaluation, you take all the details of the specific project and its permitting process into account. Next question is from Tristan Richardson at Truist Securities, and this is regarding CCUS. Regarding the 1.2 Bcf a day of CCUS opportunity that you note maybe economic today, i.e., ethanol, gas processing, et cetera, does that opportunity set require purpose-built pipe? Or what portion of that near-term potential could be addressed using KMI's existing assets. Jesse?

All right. Regarding how much of that is in proportion to our existing assets, I think it's safe to assume you've got about 200 million to 300 million in the Permian that we can handle and another 200 million to 300 million in the fourth quarter. So I think about 400 million to 600 million cubic feet a day is along our infrastructure today. So a good opportunity to start there. With regards to ethanol and others in the Midwest, I think you would need additional new infrastructure to handle those which are significant volumes. Obviously, in discussion -- early discussions with others on those opportunities as well.

Okay. All right. The next question is from Rebecca Followill USCA Securities. And can you talk about expectations for your Eagle Ford, Bakken and Jones Act tankers. So a number of segments involved here for 2022 in the next couple of years. And so I'm going to try to handle the gathering part of this. And John, if you would answer on the Jones Act tankers. So in the Eagle Ford. The Eagle Ford continues to be an extremely competitive arena. I mean the way that market is set up is that producers tend to gather to a central delivery point, which means that they can choose multiple alternatives. Now we've done okay and held our own and actually grew our volumes by about 1% there. But it is a very competitive environment. It's also integrated well with our system. The Eagle Ford has been -- hasn't come back in the same way the Permian has, but it's economic there, and we're starting to see some uptick in activity. And so -- but there is just a lot of capacity to fill up before that particular basin gets constrained. And so it's going to continue to be a very competitive environment. On the Bakken. I think, Dax really talked about this, but there's also a gas component to it as well, which is we're staying very close to our producers up there. They are expanding both in natural gas as well as in crude. And so we're going side-by-side with them as we do the build-out to accommodate their growing volumes. It's a good basin for us, because we have some successful customers up there, and they're doing well with the acreage that they have. And then, John, if you want to comment on the next couple of [ indiscernible]

Sure. Can you switch to Slide 112? Let me just start off by reminding you that the fleet that we have is the youngest, most fuel efficient and lowest emissions in the business. So we think we're well positioned there. Last year, I talked a little bit about that this was a lagging indicator to COVID. 2020, we saw absolutely no impact from a budget or a year-over-year basis from an earnings standpoint. But 2021, we saw the low point. 25% of the industry fleet of 45 total vessels was at one point or another in layup last year, which obviously negatively impacted our earnings with [ our two ] that were out. Kim discussed on the earnings call a couple of weeks ago that we're seeing green shoots in this area. But we didn't elaborate on those, and I'll kind of walk you through what those are. Two of the older vessels of the 45 were scrapped this past year, the Houston and the chemical Pioneer, which are not ours. We saw renewable diesel trade commencing. We even saw movements to the West Coast out of the Gulf. We see additional crude trade from the Gulf to the Northeast. And as we speak right now, we have -- all of our vessels are out of lay up, 100% moving. So what does that mean? Five -- as it relates to the contract, 25% of our contracts are now 5 or more years in length and 87% of our $129 million budget for next year is covered either by contracts or likely renewals. So bottom line, we see continued upside in this market. [ Navigistics], which is kind of the WoodMac for information within the Jones Act fleet, looking forward, sees continued tightening and continued pricing appreciation for the next 4, 5, 6, 7 years.

Okay. Thank you, John. Next question is from Ram Vadali, DBRS Morningstar. What portion of higher costs driven by inflation can you pass on to customers? So a little bit of a complicated answer to that. If you look at the contracts that are -- that have indexes in them, and so there's some escalation associated with whether it's the FERC rate tariff -- or the FERC tariff escalator or PPI reference or CPI is about 30%. Is that right, Peter? Right around 30%?

Yes.

Yes. And so then beyond that, the question becomes, well, how much inflation are we experiencing? And in other context, do we have the opportunity to pass it through? And so I think we've been fortunate so far in that we are not experiencing significant inflation in terms of wage pressures. There are pockets. There are pockets where we have [indiscernible] terminal where we have drivers and operators who could work for Amazon and get a signing bonus or something. But generally speaking, that's been fairly selective. And so we're kind of in line with other companies who are increasing wages by, call it, 3% or 3% to 4% for the year. So not seeing a lot there. We're seeing in some of the materials we buy, like lubricants for our compressor stations, for example, that's escalated some. But generally, we are able to keep our cost structure at least currently under what you're seeing in terms of inflation escalation. Where we see it and then pricing it is in our project budgets, for example. So the question always when we get a project that we're looking at is what steel price assumption do you have in here, have you gotten with procurement? Is this updated for the latest equipment costs, materials costs, steel costs and lead times so that we know what we're dealing with when we get this project -- if we get this project. And then what's your strategy to lock them in once you've got somebody signed up. And so that's a big part of it. But there, you price it in and make sure you've got it covered. The final part of the question would be, it really comes down to where do you have pricing power in the sense that you have the ability to pass through increases in your cost to customers. And so I mean, as you look at our network, we've got a lot of infrastructure that is -- that our customers really depend on. And so we have some, but you can't overstate that. We would look at cost escalations as part of our [ renewal ] discussions. But it is a competitive market in a lot of these businesses, and that's going to be more of a mixed bag. Anyway, the good news is we've relatively contained inflation. I think the other good news is that our escalators generally more than cover what we're experiencing and we're pricing it in on our projects. Okay. Next one is from Michael Lapides at Goldman Sachs. And this is going to be a gas question, it looks like, Tom. What are your views on the U.S. Northeast gas market medium and long-term? Long-term meaning 5-plus years, given the permitting challenges to build new infrastructure there as well as the impact offshore wind will have on power generation and state efforts like New York to reduce gas utility demand. So U.S. Northeast gas markets.

Yes. I mean I think it's a very challenging market to build any incremental infrastructure. We certainly have some projects that are really just expansions of our existing footprint. And I think those are the most likely type of projects that can be done in that area. But it is -- it's a very difficult market to expand our footprint. Yes, I think there is some competitive threats that are building over time. But I think as we talked about with the value of storage, I think that plays into backstopping that renewable power factor that we talked about earlier. And the value of both transportation and storage capacity supporting that effort in the market, I think, will grow over time. I think overall, being that it's such a constrained market right now, we are certainly seeing price values this winter on the Northeast, very strong, really competitive with what LNG markets are internationally. I think it's going to take a long time for that to be a real significant impact to the market in the long run. And I think I like our position both from a Tennessee Gas Pipeline connectivity perspective as well as our storage position, including what we've added with Stagecoach to really be a very supportive value-adder as we go forward.

Okay. Next question is for David Michels from Michael Blum in Wells Fargo. Can you discuss why you think 4.5x is the right leverage target for the company? And why something lower is suboptimal in management's view?

Yes. Good question. So first of all, as you know, the way that we look at our overall credit profile is a combination of multiple factors to leverage -- the debts to adjusted EBITDA leverage factor is just one of those. And so when you take into account our scale, diversification, our customer mix, our counterparty credit worthiness, our business mix, et cetera, we feel like the 4.5x long-term leverage target is appropriate for our business. With that being said, we don't think living underneath that is suboptimal. So it's a good question. And you can see from where we're budgeting for 2022 to end at -- end the year at 4.3x, we do see some value to living a little bit below that longer-term leverage target, and we endeavor to get there. And it looks like if everything plays out the way that -- it looks like it may, for 2022, we will be a little bit below. But in terms of what else could change it, I spoke a little bit about this on the earnings call last week that we do regularly review the potential benefit to us from a weighted average cost of capital standpoint for -- if we were to lower that leverage, would we receive a meaningfully lower cost of capital? In the current market conditions, we don't see that as the case but we do regularly review it and that could be something in the future that could prompt us to review a lower leverage target.

Okay. Next question is for you, too. Michael Cusimano at Pickering Energy Partners. Looking at the $1.15 billion of discretionary capital, excluding the SNG contribution, can you talk about the return timing on those projects across the segments? Trying to understand the contribution timing on those projects for 2023.

For 2023?

Yes.

Yes. So I'd have to take a look at this. Most of those are pretty near-term contributions. I would say, I don't have the exact number, but I would say a fair amount of those are going to start contributing in 2022. And I would say nearly all of them are going to be 2023. It maybe not a full year 2023, but will contribute EBITDA -- will be in service in 2023.

Yes, really, we were looking at this earlier. I mean, if you look at our CapEx budget, our expansion CapEx budget in 2022, the gas group, which is the biggest contributor, has got about 40 separate projects in that. And the largest one of those is in the nature of $40 million. So that's just looking at the 2022 part of it. So these are -- we're tending to see more projects that are built off of our existing footprint, which tend to be easier to execute on earlier in time and better return opportunities. Okay. Back to Michael Blum of Wells Fargo. How do you balance doing buybacks versus additional M&A? What hurdle rates are you considering between the two? I'll start on that. And look, we look at things on a risk-adjusted return basis. And so we're looking at the returns, but we're also looking at the risk. The execution risk on a share repurchase is very low. You're going to make the purchase, you're going to reduce the denominator, you're going to give the remaining shares, a higher piece of that, a higher percentage of the cash flow that you're generating. And so we look at those and we see an attractive economic opportunities in those. We are opportunistic. We judge it based on return. But we try to make those returns be on equivalent basis. So as we adjust for leverage, we adjust for risk. And so I think it's a fair conclusion to say if we're looking at M&A or even just an investment generally, we're going to want to see something that looks significantly better than what we would get just repurchasing shares.

No, I think that's exactly right, Steve. And let me just say that the management team and the Board spends an awful lot of time on this issue, and we're very cognizant of the fact that having the kind of cash flow we have is pretty unique in the world. And we are really looking very carefully at the best way to deploy that. And what it really forces you to, as a practical matter, is a very good process of weighing very carefully what the risks are in any capital project versus the [ sure handed ] thing of buying back shares. So it's an art, not a science. And I think we're doing a good job of balancing those. Thanks to Steve and the team.

All right, Peter, we still have some things in the queue?

[indiscernible]

Okay. Hold on. Okay. Tristan Richardson, Truist Securities. Thinking about the $750 million of flexibility. Across the project funnel of unsanctioned projects, what segments or types of projects currently screen as the most competitive as the backlog evolves throughout the year. David, do you want to take the first cut at that?

It's hard to say. We -- I think any of our projects that...

That's why I gave you the question.

Yes. We -- I remember going through the budget process, there were some medium likelihood type projects that we decided not to include in the budget because they just weren't advanced enough. There were some -- they were across the board, the ones that stand out, though, were in the natural gas segment, which isn't a surprise. So I'd say those are probably the ones that are -- there are some additional projects in the natural gas space that I would say are more than likely to come into play during 2022. There were a couple of others across the other segments, but that's the area that really stands out to me.

That's it. Okay. All right. Why don't you go ahead?

I'd just like to thank, again. It's a lot of work to put these together, and I just want to thank the team that's really done it, of course, Peter Staples as always has taken the laboring work. Hannah Stuckey helped a lot on this, Sean Pogue, Cheree Garza, [ Gwen Riley ] who's not here today, [indiscernible] and I just want to thank you and give you a round of applause for everything you've done to put this together. Thank you.

And I will mention, too. Many of you know, Peter, and I have worked with him for a long time over the years. And know what -- how good he is and how capable and how thorough and how responsive he is. And where I have to say Peter has been made Vice President of Investor Relations. So we'll do a separate one for that.

Don't let that go to your head, Peter.

Okay. So we're going to have -- for those who are here in Houston, we're going to have lunch, and we will have the executive team divided up among the tables. And so that will be next door, I guess, right, Peter?

Right behind you.

Right behind us. Okay. Excellent. Thank you all.