Welcome to our 2021 Investor Conference. I'm Rich Kinder, Executive Chairman of Kinder Morgan. We realize that this remote format is not as conducive to a full and open exchange of information as an in-person conference would be. Under the circumstances, it's the only real way to proceed, and we hope and trust we will be able to give you a comprehensive look at our business, our financial results, and an outlook for 2021 and beyond. Let me begin by confronting the investment climate for energy stocks head on. To many investors, the energy sector, including midstream companies like KMI, is a pariah, and their reaction is simply to avoid this sector altogether. For those who want to determine their investments on a rational basis and perhaps take advantage of undervalued companies with strong earnings and cash flow characteristics, it seems to me that an examination of a company like Kinder Morgan should wrestle with three issues. The first is whether we are managing our company in a financially viable and appropriate way. Are we spending beyond our needs? Do we maintain a solid balance sheet? Are we chasing rainbows in our discretionary CapEx program? Are we adequately covering our dividend? In our case, I think we pass this test with flying colors. As you will see later in today's presentation, we are funding all of our needs, including a solid and growing dividend, and all of our CapEx from internally generated cash flow with substantial additional cash beyond those needs to pay down debt and repurchase shares. We've paid down almost $11 billion in debt since 2015, and we maintain a solid BBB credit rating. Coverage of our dividend is robust. The second issue is whether our business has a future. Are we the equivalent of buggy whip manufacturers in the early days of the 20th century, or is there a long time period over which the products we move in our pipelines and handle in our terminals will still be a vital part of our economy, both in North America and around the world? We believe it's the latter, and that our products, especially natural gas, have a long runway ahead. Almost every serious study supports this view. I will show you some of the statistics on that in my part of the presentation. The third issue is whether we can survive and prosper in the coming energy transition. Do our assets fit with the movement to more renewable fuels? In essence, are we part of the problem or part of the solution? Steve will discuss that in detail this morning. Suffice it to say that we strongly believe our assets will play a major role in that transition. Peter, let's go to slide five. I think this summarize, in a good way, the position we've always maintained for Kinder Morgan. We're a leader in U.S. infrastructure. We have, especially natural gas pipelines and storage, which has a decades long time horizon. We've always prided ourselves on governance and being managed for shareholders by shareholders. What we're trying to do, very simply, is deliver energy to improve lives and create a better world. Slide six. We've said many times that it's very important that the interests of management and the company shareholders be aligned. To me, this is paramount to a well-run company. I say that as executive chairman and largest shareholder, and this slide indicates that we have that at Kinder Morgan. First of all, about 13% of the stock is owned by the management and board. Our equity-based compensation, I think, is industry leading. Equity-based compensation to us is a core part of our overall compensation structure, and over two-thirds of executive compensation is delivered in the form of restricted stock, which is a higher percentage than our proxy peer companies. You also have to be disciplined if you're going to run the company for your shareholders. We think we're doing that. We're a low-cost operator, which the rest of the team will talk about in some detail today. We have a high return criteria before we make capital investments. As I said, we internally fund our dividend and CapEx. We have a program to return excess cash to shareholders through a well-covered and growing dividend and through opportunistic share purchases. Slide seven. To understand the demand for energy, I believe it's important to understand worldwide demographics and the future expectations and needs of people in developing economies as they improve their lot in life. Some of the numbers on this slide are almost shocking. Across the top, you can see IEA estimates that 660 million people on this planet remain without electricity. Almost 2.5 billion people rely on traditional biomass for cooking, which, of course, is very unhealthy and very counterproductive to increasing your standard of living. As standard of living increase over the years, the energy component moves up dramatically. You can see that from this slide, how much more energy per capita the United States uses than Africa and India, for example. As these large populations in developing economies move forward on the curve of increasing prosperity, they inevitably will need more energy to advance their basic needs and their quality of life. This, overall, is what is driving energy demand over the next several decades. Slide eight. Now, as this slide says, energy usage is absolutely essential to everyday life, no matter where you live or what occupation you pursue, and this slide shows the current IEA outlook for energy demand growth between 2019 and 2040. The overall growth is, to me, pretty astounding, about 20% overall, and 34% in non-OECD countries. This is from the normal year of 2019. The sources of demand growth, as you can see from this slide, are balanced, with a little less than half of that growth coming from power demand, including heating load, and the rest from industry, transport, and other uses, including agriculture, as the world produces more food to satisfy a growing population. The great bulk of this growth will come in Asia and Africa, where we believe American exports of LNG, crude oil, and refined products will play a major role in the coming years. Slide nine. I can hear the cynics saying, We buy off on this growth story you're spinning, but won't all of the additional demand be satisfied by renewable energy? The answer is that while renewables will increase their penetration of the market as a percentage of total demand, hydrocarbons will maintain a critical role, and natural gas is actually projected to be a bigger piece of a much larger pie, with overall demand for gas to increase 29% by 2040. To return to my original analogy, we are not manufacturing buggy whips. Slide 10. This slide shows the natural gas demand growth by sector between 2019 and 2030. The two takeaways are that industrial demand is the biggest growth driver and that power demand remains resilient even as the use of renewables grow. Slide 11. Even global oil demand remains steady for at least another decade, driven by growth for fuel for trucks, aviation fuel, and petrochemicals. Slide 12. As I said earlier, U.S. production plays an important role in satisfying global demand, as IEA projects net exports of natural gas at 16 BCF a day in 2040 and estimates oil and liquids net exports of almost 4 million barrels per day by that time. Obviously, midstream players like KMI will play a major role in transporting those commodities from producing fields to export facilities on the water and to Mexico. Slide 13. To sum up, this is why we believe KMI should be a core holding in any portfolio. We may be prejudiced, and we probably are. If you look at some of these factors, they appear very critical to us. First of all, we're one of the largest energy companies in the S&P 500, with a market cap above $35 billion. As I said earlier, we have a management whose interests are highly aligned with the ownership of the stock. We have a dividend that's one of the top dividend yields in the S&P 500, about 7% at the current equity price. We expect to deliver a 3% dividend increase in 2021 versus 2020. Beyond that, we expect to have about $450 million available for buybacks in 2021 while we maintain our strong BBB balance sheet. With that, I'll turn the presentation over to our CEO, Steve Kean. Steve? All right. Thank you, Rich. Slide 15, Peter. Let's start with purpose. We deliver energy to improve lives and create a better world. That's what energy companies do. Our customers make better lives possible for our fellow citizens and for people around the world. Affordable and reliable energy is essential to human development and modern life. Pulling another 1 billion people out of poverty is dependent upon having affordable and reliable energy. You don't do that. You don't advance human development by making energy more expensive and less reliable. Energy is the gateway to abundant food, clean water, access to opportunity, and human development. We help our customers make civilization possible, and it's important how we do that, consistent with our objectives of safety, efficiency, and environmentally friendly operations, and also consistent with our core values as a company. Slide 16. Our business is resilient throughout an energy transition. As Rich said, we're going to explain how. The key to our resilience through the transition is not only what we do, that's certainly very valuable, but also how we do it. Our approach to safety, to compliance, and our attention to other ESG performance has put us in a good position with local, state, and federal governments, regardless of party. We'll keep doing business the right way and keep doing things that are valuable to the people and communities we serve. Doing valuable things in the responsible way creates resilience regardless of the way the political and social winds are blowing at the moment. We'll talk about how what we do is valuable and will be needed for a long time, how what we do today helps meet environmental goals, and how we're positioned for the future as well. Slide 17. Let's start with today. We have an unparalleled asset network. It's been built over decades. It links the major producing and demand centers in all the commodities that we serve. Those assets are hard to substitute for or replicate. We've got the largest natural gas transmission and storage network. That makes up 62% of our segment EBITDA. We are the largest independent transporter of refined products and the largest independent terminal operator. Combined, those businesses make up another 31% of our segment EBITDA. The remaining 7% is made of the pipelines and enhanced oil recovery operations in our CO2 business. I'll have more to say about that business when we get to carbon capture opportunities. Our gas and refined products businesses are tied into the nation's export infrastructure, that makes up an increasing part of our business as we and our customers serve the energy needs of developing economies around the world. Next slide. Here's a further breakdown, you can see most of our natural gas pipelines, making up that 62%, most of that is in the interstate sector, interstate pipelines and storage assets. You also see the contribution here from our Texas network, 10% of the total. Our Texas intrastate system is a great transmission system along the Texas Gulf Coast. We've got 130 BCF of storage associated with that system as well, it's in a competitive, market-driven environment, not regulated by the Federal Energy Regulatory Commission. You see our refined products business contribution. You can see it both in our refined products pipeline segment, where it's about 11%. That's, again, of the total for the company. You can add another 9% from terminals and 3% from the Jones Act tankers, which are also serving the refined products market, with transport activity between U.S. ports. This chart also shows you what our G&P contribution is. You see the 6% of the overall picture that's made up from our natural gas pipelines, and you also see the G&P in our products pipelines, on the crude side, another 1%. 7% overall there. You see the 7% in our CO2 business broken down between enhanced oil recovery, and our CO2 source and transport business. That's a little finer breakdown of our segment or overall, EBITDA from our segments and how it's broken out among the various segments as well as the sub-parts of those segments and the businesses therein. Okay, next page. Focusing first on natural gas, a few points to be made here. Again, our network connects every major supply center in the U.S. with every major demand center, including the increasingly important outlets to the export markets. Natural gas is now, and has been for the last few years, thoroughly integrated with the global natural gas market. We're well connected to those sources of demand. The demand, as you see on the lower left there, the demand is expected to grow, in almost every category. You'll see, this is the first of several slides we have in the deck today that show you or that remind us that power demand is not anywhere near the whole story. In fact, the higher-growing pieces of the natural gas demand are on the right-hand side of those bar charts. You see a lot of it is explained by exports and industrial demand driving growth. You're going to see down there, Rich touched on this too, but you see industrial demand, particularly in the global markets, driving the need for natural gas. There really aren't good substitutes there for that part of the business. I think another important point here is that the supply growth, and here we're just showing three basins, but these are the three basins that really contribute most to the growth. As you can see from the map, these are basins that we are well connected to. We've got pipe in the ground across these basins today. Gathering in the Haynesville, but long-haul pipe that serves the Permian and the Northeast market, not really gathering and processing position there. You look at that and then also look at where the demand, look at the lower right-hand part of this chart. Over 80% of the forecast demand growth is driven by Texas and Louisiana. That's a function of industrial and petchem demand on the coasts. It's also a function of our tie-in to export markets, whether that's in Mexico or the LNG facilities on the Texas and Louisiana Gulf Coast. Three-quarters of the supply growth that we're showing here from these basins, which is primarily in Louisiana and Texas, also on the supply side. There's a little bit of New Mexico in the Permian bar there. 3/4 of what we're showing here, but 80% of the overall demand growth in Texas and Louisiana. Those are environments where the economies, the state budgets, everything depends on us doing a good job of exploiting those resources and getting them to market. As a consequence, the permitting environment is more attractive. That's where the growth is coming from on the supply and the demand side, and it's a place where our network is extremely well fixed. Next slide. Okay. Again, what we do is important, but so is how we do it. This is not just about us. This is about our customers. Our U.S. customers are responsible producers of energy commodities with an advantage over nearly every other place in the world when it comes to the emissions intensity of our production. We keep getting better. Again, more on that later. Policies that drive development away from these jurisdictions, on the left, and toward countries where the emissions intensity is much higher, that's not good for the environment. It's not good for U.S. workers and businesses, certainly, but it's also not good overall for the environment and not good for the global climate. Our customers and we ourselves are responsible in the production of the energy resources that we need and that the world needs, and we move those to market in an environmentally responsible way. Next page. This is about the industrial demand that Rich mentioned, and I mentioned a moment ago. We have growing U.S. demand, in the industrial sector, and it's primarily used for process heat. What that means is it's extremely difficult to replace that in an economic way, with something other than natural gas. The everyday materials that are essential to a modern life, and to people living productive lives and having opportunity, those essential materials rely on what we do. That's fertilizer, cement, primary steel production, food processing. All of them are best served this way, and that contributes to the resilience and also to the growth of our sector. Doing all of these things, all of this manufacturing and this processing, and doing it in a way that's economic and doing it in a way that's low intensity from an emissions standpoint, relies especially on natural gas. Next page. Our infrastructure is important today, and it's also important, as we're showing here, for the future growth and energy needs both here and abroad. Gas is low emissions, it's reliable, it's dispatchable, it's abundant, it's low cost, and also a point that's often overlooked, it's a very dense form of energy. A power plant, the footprint of a gas well, for example, our pipeline footprint, which is underground, the footprint, the land use requirements for what we do as opposed to what's required for solar and wind, for example, there's an enormous difference, an enormous advantage. Those things matter, and they'll increasingly matter, as we confront those difficulties more directly. We also can move the energy. Because we move it underground, we don't have the same obstacles. It's hard to build a pipeline, but it's really hard to build electric transmission lines. A lot of what we do, the way we do it, and the long-term footprint of our network is such that it's easier to do what we do than it is to build the long-haul above ground energy transmission. All of these things, low emissions, reliable and dispatchable, which we'll get into more, abundant and low cost, and energy dense and efficient from a land use perspective. It enables economic growth without sacrificing environmental objectives, and the assets that we have are essential to making the linkage between supply and market. Slide 23. We're going to start looking at emissions here, and this is something that most of the people on this call probably know, but is not generally understood, I think, in popular understanding. What's happened, over the last more than a decade now, is that we've been reducing CO2 emissions across the U.S., a big part of that picture has been what we're able to accomplish with natural gas entering the generation stack. You see that on the left-hand side, you see how natural gas, on a quantitative basis, renewables have certainly grown in share, but in terms of absolute quantities here, the growth in natural gas in the power generation stack has pushed coal down dramatically. We'll talk about the benefits from an emissions standpoint and from an efficiency gain, in just a moment. We were at 6 gigatons, roughly. If you go back to the 2004-2007, we were really running in that 6 billion tons territory, in greenhouse gas equivalent emissions. U.S. emissions have declined about 14%, over that time period, or about 860 million metric tons. The lion's share of that being contributed by a reduction in the power sector. If you look at the power sector by itself, I believe where we're sitting now is we're back at the emissions level that the power sector experienced in the late 1980s. Okay. Pre-Kyoto, late 1980s. We're doing that with about an economy that's twice the size that it was back in the late 1980s, with about one-third more people and with about 50%, if I recall correctly, 50% more electric generation. Just an extraordinary story and one that's often overlooked. We're already over half of the goal of the Paris Agreement. We probably won't hit that, the full goal by 2025, on the current trajectory, but we accomplished over half, and we did that with American jobs and American ingenuity and with natural gas, an abundant resource that we were able to harness and use in the power sector to reduce emissions substantially. We can do more of that, and there's no reason why we can't do that in places like China and India and elsewhere in the world where there's still a heavy reliance on coal in the power sector, and if anything, a growing reliance on it as you look at the years ahead. Really an incredible story. Emissions declining since 2007 while we grew GDP by about 50%. Natural gas was a big part of that story, it can continue to be a big part of that story, not only in the U.S., but around the globe. Okay, slide 24. Again, there's no good reason why we can't replicate this experience around the world, particularly in growing economies like China and India, which already do or will shortly, in the case of China, already does, in India's case, shortly will emit more CO2 than the U.S. Gas is more efficient than coal, you see that on the left-hand part of the chart there. More efficient than coal, also less CO2-intensive for what does get burned in those more efficient facilities. You put those two factors together, that results in 60% lower CO2-equivalent emissions from using natural gas than from using coal. The other point to be made here, again, is that if you think about the energy transition, and you think about it a little more broadly, a little more globally, there are really two energy transitions. One is the energy transition that gets the headlines and gets all of our attention, and that is, and it's a very important one, the need to reduce CO2-equivalent intensity of our economies and the emissions that we make when we produce energy, when we produce power. That's one transition. I showed you the progress that we've been able to make in the private sector on that transition, there's more to come. The second energy transition, and one that's been kind of pressed to the side, at least in the U.S. and the west right now, is the energy transition in the global economy, where more and more people need access to affordable energy if we're going to improve lives and give people an opportunity at a better, productive, more meaningful existence. Instead of having families out gathering wood in the morning, and cooking with something that's not good for their health, we can supply a clean energy source, and we can improve everyone's life, and we can pull more people out of poverty. That's the second energy transition. I don't think you can have a principled discussion about undertaking an energy transition without considering both of those things, the need to meet climate objectives, as well as the need to meet human objectives. That's a big part of the story here as you look at the global economy and what's required there. We can do a lot more to shrink that 42% in China and that 34% in India and that 22% globally of coal's contribution to power generation and replace it with more and more natural gas. We can work on the climate as well as improving the air quality on the ground, for people out in the world and also in their homes. We can do a lot more to improve on both of those energy transitions, and natural gas has an especially important and meaningful role to play there. The next slide. We're not against renewable power. We help enable it. Increasingly, what we do as a pipeline company with storage assets and gas transportation assets is market what we do as deliverability, being able to provide the capacity that's needed as we put more zero emissions, at least in the production part of the cycle, more zero emissions renewable power into the generation stack. What this slide and the next slide will show you is that in solar power, in particular, you see this transpire every day. Wind, it's a function of how much the wind is blowing and over what period of time. In solar, because of the role that solar is playing and increasingly the role that it's playing, you need natural gas to backstop when the sun is no longer shining. We'll talk about energy storage here in a minute as well. This is about the role that we play as an enabler of additional renewable penetration. Go to the next slide, Peter. This is showing you the grayish boxes there, showing you over time from 2012 to 2017, and what's projected for 2027. As we take more of the base load generating facilities out of a stack, then what happens is actually the demand for that flexible load following capability, which is what we, in combination with our gas-fired generation power customers do, the demand for that actually increases. The demand for the call on our capacity, and remember, most of our capacity, whether it's storage or gas transportation, is sold on a reservation fee basis, meaning that the customers are paying for that capacity, and they're paying us a reservation fee that gives us our return of capital as well as our return on capital and covers our expenses, et cetera. The variable charge is typically just covering variable costs. That's not true everywhere, and there are some usage revenues that we rely on. For the most part, we're being paid for our capacity. We're being paid for what we can do on the peak when it's really needed. Historically, that's been about winter demand and cold weather. Increasingly, that story is about how we help enable California and New England and other places to meet their renewable penetration goals. That's what we do with natural gas, transportation, and storage. We provide the deliverability, and you can see it on these charts. As the base load goes away, and as what is substituted for it is more intermittent resources, you need the dispatchable benefit of a natural gas-fired facility supported by, supplied by a pipeline and a storage field to be able to respond and to meet those. Now, we use here an example from California, and we're showing here that this is happening every day. What you're seeing are hours through the day here. This is not a seasonal phenomenon like winters, loading storage in the summer and drawing out in the winter used to be. This is something that's required throughout the day and every day. We used a California example, but I believe in the appendix, we have a Texas example. We've got a lot of renewables in Texas, and we have the same phenomenon here. The example from California is just a leading example as we start to see this happen, not just in California and in Texas, but in other parts of the grid as well. This is the role that natural gas plays, and it plays exceedingly well, and it beats batteries by a long stretch. Natural gas storage with a peaking generation facility is the cheapest, most effective way of delivering this grid reliability. Okay, go to the next page. Here's what's needed for natural gas in serving the needs increasingly today, but also for the future. We position ourselves on the network that we have. Now, there may be some additions to storage in the future. We may do some things on the tariff front beyond what we've already done in order to enhance the service offerings, in order to serve the particular market as it's emerging. This is how we position our network. What our network is providing and earning from the services that are needed with a more decarbonized grid, short intra-day services, sufficient pipeline and storage capacity to provide the deliverability that's needed to meet demand, do it at a low cost, and also with lower emissions while keeping the grid stable. We can take the assets we have today, and we can provide these services and are providing and marketing the services this way to our customers as we enable more renewable penetration across the grid. All right. Energy storage. This is a topic of growing importance, and this is a live topic. There are RFPs out there for battery storage, et cetera, and it's recognition of what we've been talking about in the last couple of slides, which is that renewable sources are intermittent, and so there needs to be a backstop. There are a couple of things here that I think set the stage, though, that are important for us to have a better understanding of in the public policy debate as we're making these choices. First, levelized cost of energy is not the same thing as the cost of reliable, dispatchable energy. That seems axiomatic on a grid that has to be balanced in real-time, all the time. You see this all the time. Even very sophisticated sources show us graphs with attractive decline curves in LCOE, the levelized cost of energy for renewables, and lead us to the implication, wrongly so, that we won't need anything else. Right? We won't need anything other than renewable power in order to meet the demands and keep the grid reliable and keep everybody's lights on. That's one topic. The second topic that requires greater understanding are the limitations of batteries. The materials required to make them and where those sources are available, the limited duration for supporting grid reliability, even if you had all the batteries you needed, getting two hours or four hours is not enough for a grid that's dependent upon energy sources that may be out for longer periods than two or four hours. The materials that are required, the limited duration, and also the environmental cost of relying on them. This is something that's sort of mentioned but then left to the side. Whether it's renewable power, which lacks energy density, right, when compared to hydrocarbons, and certainly when compared to nuclear, or whether it's batteries, there's a current disregard or lack of emphasis on the mining that's required, the energy that's used in that mining, the land that's disturbed, the materials that are extracted and then fabricated or refined down to a very small level of the amount that's mined in order to make the materials that are needed to make a solar panel, to make a windmill, or to make a battery. Then the disposal costs, really, of all of those things. That's been not emphasized. It will be. There will be a time when we're looking at all of these considerations when we're trying to make really wise choices about what it's going to take to serve both energy transitions, the environmental one, as well as the human development one. You could also add a third topic that needs better understanding, I think, which is there's a tendency to conflate the level of progress that's been made in computation and the speed with which innovation happens in computer science, which is in computer engineering, which is fundamentally not matched with the advances and the implementable advances that are made in theoretical physics and chemistry, which is what governs more of what drives innovation and change and efficiency gains in an industrial process like our modern energy system. Okay, anyway, on this slide, what we've tried to do, just very simply, is show how what we can do is provide a better battery. The combination and the capability of natural gas storage and a peaker plant to meet energy storage needs. Even under the IEA, this is using, and you can see this in the footnotes, we're using different things in different contexts, but this is using the sustainable development scenario from IEA. Even under that scenario, the contribution of batteries, when you put it on this scale, it doesn't mean that people aren't making fine batteries and that we can't make more of them. It just means that when you sort of do all of the projecting and do all the arithmetic around it, you don't get what you need. This is done in terawatt hours of power, which does include the duration dimension here, right? It just doesn't accomplish what needs to be accomplished, and it's simply no comparison to what could be accomplished with energy storage in the form of natural gas storage and a peaking facility. We've got enough natural gas storage to power the entire country for a month. That would never happen, but that gives you an idea of, particularly when you need grid-level support, what's required and what's practical to meet that requirement. Europe has a lot of storage as well. Anyway, this is just a way of getting across a point that I think has been a bit lost in the debate, but more about making the positive point, which is we are going to have more renewables. We need to have more renewables to help us satisfy the objectives of the first energy transition. We in the natural gas business can help enable that, help make it possible, and provide the things that renewables can't. One of those things, and a very key thing, is energy storage. We've shown on here what our share, we're the largest storage provider in North America, and we've shown us the share of the overall U.S. picture. Okay, page 29. What's required, and this is as we look at what's required in terms of grid investment in order to meet the global power needs. We need to have an open-minded examination and comparison on cost, on environmental impact, and on readiness. The readiness also includes really the considerations we have around the objectives or the needs of lower-income people to bring more people out of poverty, give people more ability to live productive and meaningful lives. So whether you look at it from a cost standpoint or you look at it from an environmental impact standpoint, where you take into account everything, not just Scope 1, but Scope 2 and Scope 3 emissions, which include the activities that go into mining and go into fabrication and manufacture, et cetera. You need to have the energy policy debate taking all of those things into account. What we've shown here is network expansion by 2030, we require another 70% over 2019. As not just our analysis, but as the IEA analysis shows, that underlines the importance of adequate infrastructure planning and including the need to provide linkages with the national gas network. Slide 30. We're well-positioned to move what's needed today, but also the fuels of future. Now we're going to talk a little bit more about that. Got two shown here. These are things that responsibly sourced gas. I'll talk about a few kind of concentric circles here. What we already do today is responsibly sourced gas, which is low methane emissions gas. We've got some statistics on that to show you. We've got our role in enabling renewables, which is what we just went through. We have the ability to provide midstream services to renewable liquid fuels, something we'll talk about also. We can also serve renewable natural gas. We do this today. The quantities are very small. Typically, what's moving today on our system is landfill gas, which is the most economic capture of renewable natural gas. We can move that on our network today. Stepping out from what we can already do today are the things that we can do with the facilities that we have. That can include things like hydrogen blending into the existing natural gas stream. Also, we can transport and sequester carbon. That's what we do in our enhanced oil recovery business. Again, more on that in a moment. Then there's some further step outs, this would be new, right? We're going to be disciplined about these things, but it would be getting involved, for example, in CO2 capture or in our own renewable liquid fuels capture or production. We can provide the midstream services there on both of those. That's a further circle out. The two that are covered on this slide are renewable natural gas. Renewable natural gas can be transported and stored and used the same way we do other natural gas. It's got to be captured, it's got to be cleaned up sometimes. We can move it on our pipes and hold it in our storage facilities. Hydrogen. Hydrogen is a suitable fuel for power generation and potentially other uses. We can blend 5%-10% of it into our system, and we can move it in pipelines more efficiently than it could be turned into power and moved on electric transmission lines when you take the line losses into account on electric transmission versus what we experience on natural gas pipelines. I will caution on hydrogen as I did when we had the investor call or the earnings call last week. There's work to be done here. Part of the limitation on how much you can put in the system is an end-use limitation, and there are end users who can do more or less than this. One of our power customers who tends to have more modern natural gas facilities told me that they can blend up to 15% in some of their power plants. On the gas pipeline side, there is more work to be done in terms of the hydrogen impact on certain kinds of pipelines, and whether hydrogen entered into the pipeline can reduce the integrity of the line, in which case there would be some retrofitting involved. We'll need to measure the pace at which that unfolds, et cetera. More work to be done there. Our assets are positioned to handle it to the extent that this becomes a long-term opportunity. On slide 31. Here we're showing some of the relative supplies and costs. The ranges you see here are big. On the left, we're showing if you project out in time to 2050 what the potential is. You can see that at least even with technological improvement, which is factored in on the right-hand side, even with that, it takes a while to get to a significant number, and in this case, that significant number by 2050 is 20%. Okay. That's assuming that there is a decline in the cost of production. You see some pretty big bands here, and some of that is a function of the way that the renewable natural gas, for example, is captured, whether that's in landfill, which tends to be the bottom of those scales, or whether it's in capturing it from a cow pasture or something, or a feedlot, which tends to move it up. Then the other is over time with technological advances. You see a more dramatic change over time on green hydrogen, and that's partly a function of assumptions, again, on improved efficiency and renewable power, et cetera, to get you that advantage by the time you get to 2050. Look, these are opportunities we're attentive to, and these numbers help put them in context. Now, all these things are possible nearer term to the extent they're subsidized, and that's an important policy consideration and discussion as well. Whether it's subsidized, if you will, in the sense of having it be part of a purchase profile that utilities are going to be expected to comply with by their state commissions, or whether it's subsidized directly by tax credits and the like. That can change this picture dramatically, and that's not reflected or taken into account in the charts on the right. Okay. Page 32. Responsibly sourced gas. This is something that's important to our domestic customers and also our global customers. Our global customers, meaning those who are in the LNG business, their downstream customers want to know how much methane is being emitted so that they know what kind of offsets to buy or what kind of offsets they may be expected to buy at some point in the future. We are part of an organization called ONE Future. The ONE Future members have met the overall objective of getting the entire chain, from production to transportation storage, to distribution, down to less than 1% fugitive methane emissions and doing that by 2025. That got met seven years earlier. We're actively marketing this to customers right now. We'll get into our numbers here in just a second. Actively marketing this to our customers right now. This is going to be increasingly important. It is important to some already. LDC customers, power plant customers, and it is already important to our international customers. When I say international, I mean LNG customers serving the global market. Okay. Slide 33. Carbon capture. The development here, reflected on the lower right, is that with the treasury regulations that just got published last week, the 45Q credits now move into the economic light, if you will, ethanol production and certain natural gas processing and treating facilities for EOR use, meaning that we're at a point where the credits make the capture of CO2 from those streams economic, so that we can put them in a pipeline then and take them into our fields and use them to extract oil. There are limitations on that in terms of where we have the capability to do that and how many of those sources are around that footprint. There's been progress on the 45Q front that has helped to uncover some of those opportunities. We are well-positioned. We've got 1,300 miles of CO2 pipeline, which is more than anybody else, with a system capacity of over three BCF, about 3.3 BCF. That includes both our long-haul Cortez system. It also includes our, if you will, distribution system, the pipelines that move it throughout the Permian Basin for our use and for our customers' use. Our future opportunity to participate there is we can do what we're doing today, which is move it on our existing systems and use it to get something valuable out of the ground, like oil production. We may also be able to participate ultimately in the capture, or we may be able to joint venture with someone who is investing in the capture part of it. This will be a big part of the longer-term solution. Many scientists will say there's more CO2 in the atmosphere right now, even if you shut down all of humanity, there's more CO2 in the atmosphere right now than there should be. At some point, we're going to have to address carbon capture. We believe we have a role to play there. Now, another point I'll make quickly about it is not all pipelines work here. There are some barriers. CO2 requires high-pressure pipe. You can't just retrofit petroleum products pipelines or oil pipelines or even natural gas pipelines to move it. Our pipes are under pressure so that the CO2 stays in a liquid form. You can't just retrofit, you have to build new. Right now in West Texas, there aren't many of the sources shown on this chart. There are some, but there aren't many of these. Part of the CO2 capture and sequestration story is about doing something that we know how to do, which is build and operate these pipelines, but it's about building and operating pipelines that can operate at those kinds of pressures and are close to places where there are both sources of CO2 that we can capture in relatively pure form, and then places to put it in the ground. Okay. Those are a couple of the barriers, but this is an opportunity for us and one that we've had numerous discussions about with customers, and something that we're giving a lot of attention in Jesse Arenivas' organization. Okay. Slide 34. This is also a very attractive area, and it affects the two business segments that we haven't talked much about yet, which is our Refined Products Pipelines Business Unit, and also our Terminals Business Segment. We handle these things today, and the expectation is there's going to be dramatic growth here in renewable liquid biofuels. That solves an important problem that's not solved by electricity. Therefore, we see this growth, we see it happening even more in a two-degree scenario, and we see it particularly happening in the U.S. and China, and that drives investment 5x more than what's being invested today. $10 billion a year through 2030 versus the two billion that was spent in 2019. This is a very, we think, opportunity-rich part of the energy transition story for us. Go to the next slide. As you see, we handle renewable liquid fuels today. Most of the story there has been in ethanol and biodiesel. We're about a quarter of the market in terms of products handled versus total U.S. production in ethanol, more than a tenth on biodiesel. We've got the facilities in the right places to do more of this. We handle renewable diesel today, and we believe we're going to have additional opportunities there, particularly as Dax will get into in the California area where we have a Low Carbon Fuel Standard that's operating and makes this economic today. There, we have customers who are saying, How fast can you get us this capability? Also in the Lower Mississippi River region where John Schlosser's assets, he's got a great position, a great hub position there, and the opportunity to expand our business. One key difference here, renewable diesel is spec diesel. That's spec in the same way that petroleum diesel is. We can use that in our system. Our end users can use it today. Biodiesel, there's a blend standard for biodiesel. It's not a straight up in terms of the end use. It has to be blended, and there are blend standards. Still a valuable opportunity and one that we participate in today. We're looking at where we can establish hubs to take further advantage of the opportunity presented here. All right. ESG, have a multifaceted approach here. We've incorporated it essentially into how we do business today. Any initiative that we're undertaking, we build it into our management systems. We build it into our investment decisions. It's part of our quarterly business reviews. It's part of our annual budget process. That's how we get real leverage and traction on things that we set out to do, is we incorporate it into things that we already do, the business operating and decision-making process that we do. The results have been good to date. I wouldn't expect to be number one forever. There's going to be a lot of competition here, but we've done very well, and we're very proud of our team. This is not just an ESG team. They're an essential part of this, but it's really about our business units and their operations doing the reporting, doing the work that's required. You can see the accolades on the right here. We're very proud of this, proud of our improved ranking from MSCI, proud of our number one ranking in ESG from Sustainalytics. Going to the next page. This gets to responsibly sourced natural gas. We've been reducing our emissions for a long time in methane. We get paid to move the stuff, not to lose it. We started this back in the '90s. This has been an economically driven thing for us for a long time. Also, we're very proud of how we've been able to find additional ways to reduce our methane emissions. The allocation of that 1% from the ONE Future group that I mentioned, the allocation to transportation and storage is 0.31%. Our numbers have been running between 0.02% and 0.04%. We're running way ahead of the allocation to our sector. We are beating the target seven years ahead of schedule. We're doing very well here. This is now not just about behaving and performing responsibly, this is now about something that we have to sell to our customers in terms of responsibly sourced natural gas. Wrapping it up. I'm sorry, one more point here. We're building a diverse and inclusive and respectful workforce. This is part of doing business right also. We're very proud to have strong representation at the very senior level of the organization. 45% of our executive leadership is female or minority, and I will hasten to add that every person in every one of those positions got there on their merit and because they were the most qualified and able person to do that job. From here, a lot more is required in terms of development, in terms of succession planning and training and development. Things like procurement and how we do that, and improving our representation on the procurement side with minority and women-owned businesses. Those are the places where we have to continue to focus a lot of attention if we hope to even meet or exceed this composition as we look down the road. There's also what we do for our communities. Most of what we do, frankly, is we generate income for our shareholders so that they can make the contributions in their communities, but we also contribute in the communities where we operate, and you see those statistics on the bottom. Then finally, on slide 39, wrapping it up, we believe we're positioned well for the future, both moving the fuels of today and for the future, and we believe our assets and the way we do business are essential to a clean, reliable, and affordable energy future. With that, I'll turn it over to Kim. Okay. Thanks, Steve. Okay, Peter, if you'll go to slide 41. 2020, a remarkable year in energy. I can think of a few more adjectives to describe it. Unpleasant, painful, but maybe historic is a good description. In the last century, only the world wars and the Great Depression have produced larger declines in global energy demand. Globally, energy demand declined about 5% in 2020. If you look at the U.S., U.S. energy consumption fell by 8%. Natural gas consumption in the U.S. declined by 2% instead of growing as it was expected to do. Liquid fuels consumption dropped by 12%, and upstream spending on shale decreased by 50%. The U.S. rig count experienced its most abrupt decline since Baker Hughes began tracking it in 1975. If you look, it's about a 70% decline in a little over 20 weeks. If you go the next slide. We weathered the storm very well while improving shareholder value. At Kinder Morgan, we came into 2020 in a strong position, having spent the last five years reducing debt and having reduced almost $10 billion in debt. With the impacts resulting from the OPEC decision, and the pandemic, we made some significant changes. We started by cutting $700 million in CapEx, which is about a 30% reduction to our budget. We saved about $190 million in operating costs and sustaining capital, and that resulted in a $200 million improvement in distributable cash flow after discretionary capital versus our budget. We reduced debt by almost $1 billion, and that was primarily as a result from the proceeds from the sale of our interest in KML, which was our Canadian subsidiary. We paid $2.4 billion to our shareholders. That was a 9% increase over 2019, and that dividend was well-covered. We had 1.9x coverage of that dividend. During the middle of the pandemic, we completed our Permian Highway Pipeline, that brings gas to the Gulf Coast from the Permian. On the next slide, let me spend a minute talking about our strategy. We're focused on stable fee-based assets that are core to the energy infrastructure and operating those in a safe and efficient manner. We invest in low carbon future. If you look at our backlog, our $1.5 billion backlog, about 60% of that's allocated to natural gas. About 70% of our 2020 expansion was allocated to natural gas, and about 65% of our 2021 budget is allocated to natural gas. We want to maintain financial flexibility. We target a debt to EBITDA of about 4.5x. Our 2021 budget of 4.6x is consistent with that target. We have a low cost of capital as a result of a strong balance sheet. We have ample liquidity, and we've got a $4 billion undrawn revolver, and at the end of the year, we had approximately $1.2 billion of cash on hand. We continue to be very disciplined in the way we allocate capital. We have very conservative assumptions when we're underwriting projects. For example, if we have a 10-year contract, and when that contract rolls off, we don't assume that it necessarily renews at existing rates. A lot of times we are cutting the renewal assumption by a third, a half. Other times, we're assuming zero on the terminal value. Conservative assumptions when we're looking at projects, and high return thresholds. On average, we target about 15% unlevered after tax. Now, for projects with less risk, we're going to be slightly less than that. For projects with more risk, then they need a higher return. We're self-funding. We've been paying for the last five years, 100% of our dividends and our CapEx with operating cash flow. Our goal is to enhance shareholder value, and we do this by maintaining a strong balance sheet, by investing in attractive projects, and then by returning excess cash flow to our investors through a growing dividend and share repurchases. Last year, we undertook an organizational efficiency project which resulted in annual cost savings of about $100 million. As a result of that project, we centralized certain functions, which previously each of our four business segments had their own independent group. For example, we now have one project management team when we previously had four project management teams. We think not only will this make us more efficient, we expect that we will pick up effectiveness as a result of this, because now we've taken the best people across the company and put them together in one group. As part of our project, we also looked at areas where we had reduced activity, and that was primarily in our Gathering and Processing assets, and reduced headcount there. The reorganization resulted in about a 5% reduction in workforce. We were able to prevent some of the involuntary severances by offering voluntary severance for people and by filling open positions in the company with people who would've otherwise been severed. Where we ended up was only 2% of the severances were voluntary of the 5% reduction. We were already a lean organization coming into this positions us even more strongly as the low-cost provider in our industry. On the next slide, we have a conservative funding policy. Since 2016, we have been self-funding our CapEx and dividends. If you look over that five-year timeframe, we have generated $23.7 billion in cash flow from operation. That's 2/3 of our market cap. In addition, with that money, we were able to pay our dividends, our CapEx, and we have $1.9 billion in excess of those items. As we've already referenced on this call, we paid down significant debt over that timeframe, primarily from asset sales. Go on to the next slide. The first prong in our strategy is owning assets that generate very stable cash flow. Part of that stability comes from the fact that 72% of our cash flow is backed by take-or-pay contracts or hedged earnings. If you look at how our contract mix breaks down, 68% of our cash flow is backed by take-or-pay contracts. Here, we're entitled to payment regardless of throughput or commodity price. We're getting paid a fee for the capacity that we have. 25% is fee-based, meaning we have a fixed fee that we collect regardless of the commodity price, but it's based on the volumes that we move. We don't have any price exposure, but volumes do matter here. An example of these businesses are our refined products volumes, and some of our gathering and processing assets. We've got 4% of our cash flow that is hedged. Here, we don't have any price exposure in the near term, but we do have price exposure in the longer term. Then we have 3% that is commodity-based. Our exposure, the primary commodity that we're exposed to there is crude oil. There, it's about $3 million for every $1 per barrel change in oil. Pretty minimal commodity exposure. On the next slide, also contributing to the stability and security of our cash flows is the fact that over 70% of our customers are end users. These are people who need our services to be able to run their businesses. On the credit rating side, 74% is investment grade or we have substantial credit support. If you look at where we could have exposure on the 4% that is B- or below, when you net out where we could remarket that capacity, and when you look at the collateral that we have, that 4% is reduced to approximately 1%. Very little exposure on the credit side. A large part of it is due to the fact that our customers need our services. Go on to the next slide. Part of delivering value to our shareholders is identifying attractive projects to invest in and delivering those projects on time and on budget. If you look at the projects that we've completed between 2018 and 2020. At the time of investment, we expected that we would achieve about a six times investment multiple. An investment multiple here, as we're defining it, is capital invested over the year two projected EBITDA. When we actually completed those projects, we achieved a 5.6x investment multiple. That's because we completed those projects for less than the original cost estimate. If you look at our natural gas projects during this time frame, which was about 90% of our CapEx, you'll hear very similar numbers. We expected to achieve 6x, and we actually achieved 5.6x. Very good performance in terms of building our projects on time and on budget. People often ask, "How can you achieve these returns in a competitive market?" The answer is, it's because of our ability to leverage our footprint, where we've got almost 80,000 miles of pipelines, and millions of barrels of storage. I'd say another differentiating factor is also the fact that the success we've had completing our projects on time and on budget. The best example of that is PHP, and we talked about this in our quarterly earnings call last week. We had significant opposition to that project and legal challenges, and permitting delays. For example, we had to battle through one temporary restraining order and three permanent injunctions in court. Our permits were four and a half months late versus what we expected, yet we still delivered that project only three months later than our original projection. Being able to get projects done like that gives our customers confidence in relying on us. Moving to our segments, and starting with the natural gas segment. Here we have 70,000 miles of pipe. We move approximately 40% of the natural gas transported in the U.S. We move over 40% of the volumes transported to LNG facilities. We move over 55% of the volumes transported to Mexico. We expect to generate $4.4 billion in earnings before depreciation and amortization in 2021. As Steve showed you, that's about 60% of segment earnings. Now we've got a great position coming out of the Permian. On the next slide, Peter. Our pipes provide roughly seven and a half BCF of capacity out of the Permian Basin. It allows our shippers to take volumes to the desert Southwest, out to California. They can go to the Mid-Continent. We've got over four BCFs, about 4.1 BCF, that comes down to the Texas Gulf Coast, where we've got intrastate pipeline systems with about 8.3 BCF a day of capacity. We've invested $250 million over the last couple of years to increase that capacity there by 1.4 BCF a day to get to the 8.3. Off of this system, our customers have access to industrial demand, to power markets, to LNG export facilities, and to Mexico. If you look at our Permian position, the two pipelines, Gulf Coast Express and Permian Highway, a little over four BCF of the seven and a half BCF that we have. About 50% of the capacity we've built in the last two years. That's underpinned by 10-year take-or-pay contracts. On the next slide, we also support the build-out of U.S. LNG. As I mentioned earlier, KM transports over 40% of the natural gas moving to LNG export facilities. In the fourth quarter, we moved almost 4.8 BCF a day of gas to LNG facilities. We've got about 4.4 BCF a day contracted currently. We've also got 1.7 BCF a day that's contracted capacity that will come online. In total, we will have about six BCF a day contracted to LNG facilities. That doesn't include the capacity that we have contracted to producers and marketers that are also moving volumes to LNG facilities. That's currently about another BCF a day. We've got 17 years remaining on our contract terms with these LNG facilities, and we're also in active discussions for incremental volumes. Why do we have such an advantage? We've got a huge network of pipelines, especially in and around the Gulf Coast. We've got supply diversity, so we can provide our shippers with access to many different supply basins. The storage position that we have gives us deliverability, which is very important to these facilities. Tremendous position in providing transport to U.S. LNG export facilities. I'm not going to go through all of these, but just to mention a few. On the export side, Steve showed you that WoodMac's projecting about a 20 BCF a day growth over the next 10 years in natural gas demand. About 70% of that growth is coming from exports to LNG facilities and to Mexico. Given our position on the Gulf Coast, we're well-positioned to take our share of that growth. Our storage position's becoming increasingly important. LNG export facilities experience interruptions. They experience cargo cancellations. They experience weather events. If there's fog on the Texas Gulf Coast and these ships can't come in, and people are moving two BCF a day or five BCF a day or seven BCF a day towards these facilities, and all of a sudden, they've got to change and go another direction, storage becomes very important. Mexico market doesn't have a lot of storage, yet they've got daily variability in load, and they've got seasonal variability in load. There's opportunity to provide storage to Mexico using our assets on the U.S. side of the border. Then, intermittent renewable generation. There's an opportunity to support that because when you get to peak loads, and Steve showed you this in California, you're going to need to bring gas out of storage to meet those peak loads. Storage becomes increasingly important given the growth in renewable generation. Petrochemical and other industrial demand growth. Now, WoodMac projects out of their 20 BCF of growth, about five BCF of that is coming from industrial demand. A lot of that industrial demand is on the U.S. Gulf Coast, where we have a very good position. We have a continued opportunity to leverage our existing footprint, our 70,000 miles of pipe. We can continue to build extensions off of our existing network. There's opportunities to potentially repurpose assets, to tailor services for non-ratable demand, and also to transport responsibly sourced gas. We're also well-positioned, as Steve mentioned, to transport potential fuels of the future, like renewable natural gas and hydrogen. Moving to the product segment. Here we have about 9,500 miles of pipe. Our throughput in 2021, we're budgeting to be about 2.3 million barrels a day. We've got about 55 million barrels of tankage, and we expect to produce about $1.2 billion of earnings before depreciation and amortization. That's about 16% of KMI overall, and as Steve showed you, and then it's a 13% increase over 2020. That's driven primarily by a recovery in refined products volumes, which we will go through when David goes through the budget. If you look at a breakdown of our volumes in the product segment, 47% is gasoline. About 74% of that is on our western pipelines and assets. About 26% is in the southeast. On diesel fuel, diesel fuel is about 16% of the volumes, and similar breakout between west and southeast, about three-fourths in the west and about a fourth in the southeast. Our budget assumption on road fuels is that we start out weaker than 2019, we're flat with 2019 by the fourth quarter, that results in an average for the year of about 2% below 2019. Jet fuel is about 13% of our volumes. West is over 80%. It's about 82%. The Southeast is 18%. Our budget assumption here is that we're about 12% below 2019 jet fuel volumes on average. Again, we start the year much weaker than 2019 then approach 2019 levels by the fourth quarter. Crude oil is about 25% of the volumes in the product segment, roughly split between the Bakken and Texas. Steve showed you the projected growth in liquids biofuels, one area where we have current significant customer interest, as he mentioned, is on the West Coast renewable diesel. The tax incentives provided in California average about $3 per barrel, which makes this a very attractive business for our customers. We're currently in customer conversations for the construction of some renewable diesel hubs, both in Northern and Southern California. That could amount to about $90 million in discretionary CapEx for all the locations. This would be at existing terminal sites. It would involve the rail end of the biodiesel, then we would blend it at our terminals. We can accommodate blends from 5%-20%. Given our position serving the entire California diesel market, I think we're in a nice position to accommodate any transition to renewable diesel. On the terminals business segment, here we have about 29 bulk terminals and about 50 liquids terminals. If you break down this business from a revenue perspective, about 75% of this business from a revenue perspective is liquids terminals. About 25% is bulk terminals. If you do it on an EBITDA basis, because the liquids terminals have a little bit higher margins, it's about 80% liquids on EBITDA and 20% bulk. Our liquids position is about 2/3 petroleum products and about 1/3 renewables and chemicals. On the bulk side, the two largest materials that we handle are petroleum petcoke for the refiners, and metals and ores which supports the steel manufacturing. On the next slide 57, over half of our terminal's liquids capacity. We've got about 80 million barrels of liquids capacity in our Terminals Segment. Over half of that, 43 million barrels, is located in the Houston Ship Channel. These are incredible facilities, the fact that there are so many barrels and that creates enormous liquidity for our customers, that's important. What makes these facilities so special is their connectivity. We have 29 inbound pipes. We've got 18 outbound pipes. We've got 16 cross-channel lines, 11 ship docks, 39 barge spots, 35 truck bays, and three unit train facilities. These types of facilities are incredibly difficult to replicate and incredibly expensive to replicate. When you look at the next slide, I want to talk about how all these facilities work together. On the inbound side, we've got 10 refineries that we're connected to. Those refineries produce roughly two and a half million barrels a day of product. Okay? We're connected to eight chemical facilities, and we bring in chemicals for chemical tanks and also gasoline blending components from those chemical facilities. We've got unit train receipts of ethanol. We've got pipeline connections to Mont Belvieu, where we can bring in butanes and natural gasoline. We bring those products into our terminals and we aggregate them. We aggregate them so that people can get sufficient amounts. If they're trying to load a ship, they can aggregate enough product to be able to load that ship. We also help stage. When the refiners produce all this material, they can't immediately get those barrels onto outbound pipelines. We stage, we hold those barrels for them until they can get on an outbound pipeline or until they can get their product out over the truck rack. We aggregate, and we stage, and we store. We provide ancillary services such as blending, and so butane blending. All this, there's enormous liquidity and there's enormous optionality in being able to blend, and being able to stage, and being able to aggregate. They have multiple options on the outbound market access side. They can go over the truck rack. We've got the largest truck rack serving the Houston market. They can go outbound over pipelines. We're connected to Colonial, which will take them to the southeast and into the northeast markets. We have access to Explorer, which takes them to the Midwest and up into Chicago. We have rail access, which barrels are being railed to Mexico, and we have marine access, both the Jones Act as well as barges. These facilities are more than just a bucket. There's a lot of people that can go build a tank, but replicating these facilities is near impossible. U.S. Gulf Coast has some of the most efficient refining capacity in the world. We produce one of the cheapest refined product barrels in the world on the U.S. Gulf Coast. World demand continues to grow, and refineries continue to creep up their production capacity. As a result, we expect exports to continue to grow. If you look in 2020, COVID had an impact, but there was a very quick recovery. Right now, if you look at our dock capability, we've got over 600,000 barrels of dock capacity. We are using less than 50% of that today. We've got room to accommodate increased exports. Turning to the CO2 segment. These are fully integrated assets. We've got CO2 source fields in southwest Colorado. We've got pipelines that move the CO2 down into the Permian Basin, where we inject CO2 into our own oil fields as well as sell it to third parties. CO2 is projected to produce EBITDA of about $500 million this year. That's about 7% of our overall KMI EBITDA. If you break down the 7%, 5% relates to our oil and gas assets, and about 2% relates to CO2 sales and transport. The CO2 segment consistently generates free cash flow. Now let's starting on the left-hand side with the operating cost. Our cash costs on CO2 have consistently been, over the last five years, about $20 a barrel. When you look at our average realized price, anywhere from $49 to $62, even at the low end, we still have very healthy margins on the operating side. You look at the right-hand side of the page where we incorporate not only the operating margins, but the CapEx that we spend. We have produced significant free cash flow in this business over the last five years. If you look, the free cash flow ranges from $340 million to $640 million in any given year, on average, from 2016, including the 2021 budget, it's about $450 million. There's a whole bunch of reasons why our CO2 business is different from other primary production. I think another thing that makes us very different is the amount of free cash flow that this business unit consistently produces. In high price environments, of course, we produce more free cash flow. You can see $640 million when we had the highest prices. Even at the low price environments, it's around $350 million. On the last slide, we think KMI represents a compelling investment opportunity. We've got stable cash flows with 72% take-or-pay our hedged earnings. We've got a 7% current yield with almost 2x coverage, and we're one of the top 10 dividend yields in the S&P 500. We fully funded our dividends and CapEx with operating cash flow since 2016, and we expect to have approximately $450 million available for share repurchases in 2021. We've got a highly aligned management team that's got a 13% share ownership position. With that, we are going to take a 10-minute break. It's 9:27 right now, so how about we make that a 13-minute break and start back up at 9:40? [Break] All right, thanks. Welcome back, everybody. We're going to start the panel with the business unit presidents here, and I have one question for each of them that we'll go through to get things started, and then we'll also take questions from the participants. Just a reminder, we do have a full Q&A as we normally do on Investor Day at the end of the session, after David Michels, our CFO, presents the 2021 budget. We'd ask that you focus your questions here. You'll have another crack at this later, but focus your questions here on those things that are for the business unit presidents, specifically. For our registered participants, you will see that there's a dialog box below the slide that you see that will allow you to enter questions. As I said, I will kick it off. First, let me introduce everyone. On the phone here, or on the conference, we have James Holland. James is the former President of our Products Pipeline group and is the Chief Operating Officer for Kinder Morgan. Tom Martin, the President of our Natural Gas Pipeline business unit. Jesse Arenivas, President of our CO2 business unit, and John Schlosser, President of our Terminals business unit. Dax Sanders, President of our Products Pipeline business unit. Okay. All right. James, I'm going to start with you. Please describe your new role for our participants here and provide a little more detail on what you see as the additional benefits that we expect from the efficiency and effectiveness project. I'll let you know if you missed anything, James. Thanks. Go ahead. All right. As you may recall, originally contemplated this role was to go back and focus on operational excellence across the business units to make sure that we were utilizing best practices and to, again, try to further enhance our operations. In addition to that, it was also to look at our ESG program and move that forward as well, getting our greenhouse gas inventory taken care of this year for our 2020 ESG report, to look at reducing greenhouse gas emissions over some period of time. Shortly after I moved into this role, we decided to centralize, which you can see the screen up here, and we brought several departments out of the business segments into the centralized organization. The goal now is to not only to maintain those efficiencies, but also to increase our overall effectiveness. When I say effectiveness, I mean making sure that we are still providing the services back to the business units that they need in the areas of pipeline integrity, EHS, ESG, and our engineering services. Steve, I see there's really a lot of upside going forward as we, again, integrate best practices. Our agency interaction will become a lot more streamlined. We already get projects done, I think we'll be a lot more efficient in dealing with local and state and federal agencies. One big item for me is really on employee development. Right. With the structure the way we have it today, there's going to be a lot more opportunities for employees to work across assets and increase their knowledge base, which again, will benefit us in the long run. Lots more upside. We're just getting started, looking forward to the challenge. All right. Excellent. Thank you, James. My next question is for Tom Martin. Tom, if you could, describe the near-term and long-term opportunities in the gas group related to the energy transition. Thanks, Steve. I think as of right now and in the near term, to intermediate term, we're really contributing a lot to the reduction of emissions in the power sector, both domestically and internationally, through our gas deliveries across our vast gas pipeline network. We see opportunities to grow those volumes, as those opportunities continue to grow, both domestically and internationally. We also are supporting the use and growth of renewable energy by providing non-ratable gas transmission and storage services, to firm up or back up the intermittency of wind and power generation. We've seen this trend for several years in the West. It's been slowly migrating towards some of the eastern grids. Steve, you touched on ERCOT. We're seeing it now and expect this need for firming the intermittency of renewable energy. We see that trend continuing to go east and the demand for those services and those opportunities to continue to grow. We are a current shipper of renewable natural gas. It's a very small volume market today, just a little bit under 100,000 a day. We think that can scale up to about 1.5% of the U.S. production over time, maybe 1.5 BCF a day. We currently serve from five different sites on three of our different pipelines. That's just another way we can provide additional capability into the energy transition. Probably the biggest current and near-term opportunity, I think, is more on the responsibly sourced gas front. Steve, you touched on our participation in ONE Future. The members of that organization represent about 11% of the current U.S. gas production. I think working with those customers and our downstream customers and gaining additional participation in this effort, I think, really is the most impactful way that we can reduce emissions. It's also going to be a value adder, I think, and a distinguishing factor for incremental projects as we go forward, especially for the export markets, but I think even for some of the domestic markets. We are also looking and working on opportunities to incorporate clean power across our pipeline footprint, which will be an opportunity to reduce our power costs as well as lower our emissions. Longer term, hydrogen is certainly an opportunity. We think that market has the potential to grow to be somewhere in the scale of maybe 25% of the current gas market by 2050. There's a lot of analysis, a lot of work to be done for that to be realized. Many of those things we've talked about already. I mean, the metallurgical evaluation of our pipeline footprint, and the industry's pipeline footprint, really. Operating parameters of what it would take to blend hydrogen in our lines. We think there's an opportunity, just to blend a small amount of hydrogen, without a lot of incremental, if any, incremental investment. That's an exciting opportunity. Again, as we're working with our current gas customers and working with potential hydrogen customers, obviously, there's a lot of operating parameter issues to be worked through, regulatory issues that need to be worked through, as well as I said, the pipeline metallurgical issues to be considered. Again, an exciting opportunity for the industry. I think it clearly provides an uplift in terminal value of our gas pipelines, even after the long runway that we already have. With offshoots of that, there may be potential hydrogen production investment opportunities as well as opportunities to use our existing right of way across our 70,000 miles of pipeline for additional power transmission corridors, which are clearly going to be needed given the density issues we've raised on renewable energy. Okay. All right. Very good, Tom. Especially, I think, a noteworthy point on hydrogen. The timing, but also the fact that it's a very long-term play that can change fundamentally how you think about terminal value on the network. We're going to continue through with the other presidents on the theme of opportunities created by the energy transition. Dax, I'm going to ask you to focus specifically on what you see in renewable fuels, and particularly on renewable diesel. Yeah, sure. Thanks, Steve. Well, I'm going to expand a bit on what Kim's already said. Overall, I think the greatest growth opportunity for us is renewable diesel on the West Coast, and specifically in California. At this point, our conversations with our customers, that's where the demand is. It really is driven by the blending credits. If you have a gallon of renewable diesel in the U.S., you want to get it to California. Right now, between the $1 per gallon federal blenders tax credit and the California Low Carbon Fuel Standard credit, specifically in California, you're looking at a credit of $3 a gallon plus. In fact, I was reading a Platts publication the last couple of days, and so it looks like the credit, and it's dependent upon the feedstock average, just under $3.60 for the month of December. A pretty strong incentive to get those barrels there. Talk about a couple of projects that we're working on right now. I'm going to pause for a second and just give a little bit, a high level on the difference between renewable diesel and biodiesel. They're first cousins. They're not exactly the same thing. They both come generally from the same feedstock. Renewable diesel, in most cases, has been through a hydrotreater. Biodiesel is largely the result of chemical mixture and reaction. The most important thing, for our purposes, is that renewable diesel is mostly the same thing as hydrocarbon diesel. It can be seamlessly blended into hydrocarbon diesel. In fact, I believe a diesel engine can run off 100% renewable, which is certainly not the case with biodiesel. Biodiesel is not the same thing. Among the other differences from an infrastructure perspective, biodiesel gels in cooler temperatures, and it can leave a residue. It's not as easily transported through a pipe or handled, and it can contaminate jet fuel. Whereas again, renewable diesel is a much more versatile product. While we are seeing some interest in biodiesel and we are doing some biodiesel, I think the greater opportunity is going to be with renewable diesel. We've got a few smaller projects in the West that are close to in-service handling, mainly biodiesel, but some renewable diesel as well, that we're working on/completing right now. But the bigger opportunity, again, is to build, as Kim said, what we view are potential hubs for renewable diesel. One in Northern California, and one in Southern California. We're in pretty advanced conversations with shippers right now. As Kim said, in aggregate, the opportunity set right now looks to be about $90 million of capital with nice returns that absolutely meet our return thresholds with pretty conservative assumptions. We certainly hope over time that can morph into something bigger. That's kind of what we see from a near-term perspective. The initial projects will allow for a mix of truck in, rail in, morphing into rail in, with rack blending and truck out. Sometimes the question gets raised around this is whether railing renewable diesel in is a negative for our existing pipelines. We ship a lot of hydrocarbon diesel right now. The answer is not really. We view it as neutral to positive. Take Southern California, for example. Right now, the line that, specifically, this is a line from our Watson to Colton facility, and the Southern California facility would be at Colton. That line's in proration, or rather, not in this environment, but in a normal environment, a pre-COVID environment, it's in proration. That's a line that transports all products. If we took some diesel off of that line, we should be able to pick up gasoline volumes to replace it. We've got a similar dynamic in Northern California. The line segment that we're looking at there was almost in proration, not quite. We believed that it would be in proration absent the COVID environment. Anyway, the overall impact should be, our view is neutral to positive from isolating the pipeline impact. Over time, I think, as everybody knows, a lot of the PADD 5 or a couple of the PADD 5 refiners have announced that they're shutting refineries down, existing hydrocarbon refineries down, converting to or evaluating converting to renewable diesel. Obviously, they've already got the hydrotreater there, they're looking to that. Those volumes we expect, and we're hearing from our customers, could likely move to the pipeline over time. They also could come in across the dock which we've got a great dock in Los Angeles, in Southern California that could accommodate those and provide for some additional opportunity. If that happens over time, I think that is, again, same thing, neutral to positive. As long as there's inland demand for diesel, if a gallon of hydrocarbon diesel comes off and is replaced by renewable diesel, it really is the same thing. Anyway, I think we're a large player out in California. We are not the only player, and certainly, there are some potential customers that are refiners that have some of their own infrastructure. We think this is a pretty good opportunity and we're going to work it pretty hard and hopefully it turns and we can get it to fruition and it comes to something bigger. All right. Thank you, Dax. John Schlosser, we'll have an energy transition question for you too. First, why don't you talk about the pandemic, how it affected your business, and how you see demand on your assets recovering? Thanks, Steve. I would be remiss if I didn't first start off by calling out the performance of our 3,000+ employees in the terminal sector. Steve likes to say we're great at disasters. I don't care whether it's hurricanes, tornadoes, wind, rain. We have a playbook for everything. Unfortunately, there was no playbook for COVID. It was a lot of effort, ingenuity from the field, adjusting our work practices in order to keep our employees safe and our customers' products moving throughout the year, an absolutely outstanding effort. We did see improvements in each and every month from May on. For example, in Q4, we were down on a year-over-year basis $31.3 million. Remember, we sold KML in late 2019. That had an impact of $32.6 million. Even with the lingering impact of COVID, which we estimate about $11.4 million in Q4 million, we showed a slight year-over-year increase in our business. We're already seeing large recovery in gasoline and diesel, we expect it to further improve as vaccinations and reopenings occur. We, as Kim mentioned, we're budgeting back to a pre-COVID-19 level by the end of the year. The real million-dollar question, though, is what lasting changes will we see in work, school, and traveling? We'd be guessing if we told you we knew the answer to that at this point. Lastly is a point that was made earlier, and that is we took a much less impact in the terminaling side than most organizations because of the way we've contracted our business. The majority of our business is contracted. The majority, as I've mentioned in the past, is monthly warehousing charges. Our customers pay a fee for a lease of the vessel, then it's paid in advance at the beginning of the month. We continue to see very strong demand for tankage in our services. At the outset of COVID, we were able to lease practically all of our large tanks. We hit a high water mark in Q3, effective utilization at about 99%. We only had seven large tanks greater than 10,000 barrels at that point out of our 80 million barrels of total storage. As we sit today, there's only nine total tanks available anywhere in our network greater than 10,000 barrels for a total of about 302,000 barrels to remain to be leased. Overall yes, we've seen significant consistent improvement. The impact of terminals has been less because of the high demand for tankage, and we see that improving throughout the year. Okay. John, why don't you talk about how the Terminals business is positioned to participate in the energy transition? Sure, Steve. Most relevant to us is obviously liquid renewables and very similar to what Dax mentioned. Ethanol is a very big part of our business, biodiesel and renewable diesel. Kim walked you through some statistics which are in front of you right now. We are one of the largest handlers of ethanol in North America. We handle somewhere between 25% and 30% of the total ethanol marketplace. We are the CME price point for ethanol at our Argo facility, which really requires a significant amount of liquidity there and a reason why most of the customers want to be at our Argo facility. We handle somewhere between 15% and 17% of the renewable diesel. Kind of hidden in this is we are one of the largest handlers of organic veg oils and fats, which is really the feedstock for both biodiesel and for renewable diesel. From a terminaling standpoint, we'll be looking at opportunities primarily on the renewable diesel feedstock side. Much like ethanol, a lot of those feedstocks come from the Midwest Corn Belt where we have a very strong terminaling presence, and then also, as Kim mentioned, in the Lower River where we have a very significant presence as well. Longer term, we expect to see low carbon standards adopted in other states, probably the Northeast and the Mid-Atlantic where we also have significant terminal logistics platform. Let me refer you to two slides quickly here. Pete, if you could go to slide 122. We have an incredible infrastructural platform in our terminaling group. As a wise man once told me, What's your hook? Our hook is the infrastructure we already have in the ground. Seven million or 79 terminals, 80 million barrels of storage, 101 marine docks, 165 barge docks, 462 truck bays, 6,800 rail car spots, 3.5 million sq ft of warehouse, and we're long on land at most of our facilities. If it's a liquid molecule, we could handle it at these facilities. We have the investment already in place. We have the infrastructure already in place. In many areas, we're looking at co-locating production facilities on our existing assets. It's these infrastructural investments that allow us to be the energy leader we are today, as well as the energy leader of tomorrow. If you could also flip to slide either 57 or 113. Kim walked you heavily through our Houston assets, where we've invested $2.1 billion. This is the most competitive refining and petrochemical production in the world. As we transition domestically, global demand continues to grow. Kim talked about, but we have 55% upside capacity with no additional capital required. We could handle 600,000 barrels a day over the docks, and we're handling far less than 300 today. A lot of headroom in that regard. We're very well-positioned to capture this recovering global demand as we continue to focus on transition opportunities throughout our network as well. Okay. All right. Thank you, John. Okay. Jesse, you obviously have a significant CO2 business that you're running today that is generating significant free cash flow after CapEx. You're moving CO2 for our business and for third parties. You're putting it in the ground in our business, getting oil out in return. Significant operation already today. How do you see us participating in the carbon capture part of that picture, and how do you see that business growing over time? Thanks, Steve. Yeah, we see a growth story here for Kinder Morgan. The recent finalization of the 45Q regs provided much-needed clarity for market participants to invest. We think the financial incentives and regulations are pretty well aligned today, given the advantages in technology to continue to drive the cost of capture down. For those reasons, we think it's a growth opportunity. We also feel the footprint that we have in our CO2 transportation network, both handling and operation facilities, give us a competitive advantage and position as well to facilitate the growth in CCUS. As you mentioned earlier, we operate over 1,500 miles of pipeline, over three BCF of total capacity. We have very high specialized skill sets. Our expertise in investing in the design, construction, operation of both transport, separation, and handling facilities. We are the leader in the EOR space, which is the preferred, most economic disposition option for captured CO2. With that, we've developed the CO2 market over the last 20 years, and we bring the commercial expertise that's going to be necessary to connect the emissions source to the ultimate sequestration site. There are some challenges along the way. We believe you're going to need some additional government, both financial and regulatory incentives. The economics continue to improve, but as we showed on the slide on the page, the cost isn't quite an economic proposition today. Again, I think it's a growth opportunity. I think we will play a strategic and key role in developing throughout the United States. We believe we will develop that market along the infrastructure first. We'll continue our disciplined approach, analyze or evaluate strategic alternatives that both benefit the environment and our shareholders. Overall, we think this is a growth opportunity for CO2. All right. Very good. Okay. We have a number of questions that have been submitted. Tom, there are a series of questions from Shneur Gershuni at UBS regarding hydrogen. One of them you spoke to in terms of the terminal value, I'll read off another one for you. As you think about the energy transition, could you talk about the different hydrogen options, both green and blue hydrogen? I think the best way to think about that is what the customer interest and demand is. Each of those have variable scale and economies considerations. I think at the end of the day, the way this market will evolve is more of a localized micro-market, short hauls, if you will, on our network over time. As it grows, then more into long-haul opportunities. I think we'll look at each of those particular hydrogen impacts on our assets and address that, but that's a lot of work yet to be done. I think ultimately the market's going to be driven by the scale and the economics of each of those types of products. Okay. Why don't you speak also to any investments that we might make, presuming this is on the interstate portion of our network and the ability to include those in rate base as well. I think, again, depending on the timing and scale of this opportunity, we may end up being able to segregate either whole lines if we've got dual lines in the same ditch. It would have to require some additional CapEx to handle all of that capability. I think as scale and demand of hydrogen grows, we will certainly be able to grow with it. They'll certainly need to be worked on with both state, local, and federal regulators in making that happen. Would certainly expect all of that to be under interstate assets, specifically would be under jurisdiction that we would have to manage through our rate base there. Okay, we've got a question from Selman Akyol at Stifel, also hydrogen related. If KMI moves hydrogen on its pipelines, does that allow KMI to reopen contracts and change prices? Any increased costs associated with transporting hydrogen, not just compression, but costs in general? Yeah. I think for our current gas customers, we would certainly have to manage those under the current contractual arrangements. There may be some opportunity to negotiate some resolutions to those as hydrogen comes into play. As far as hydrogen itself, that'll be a separate negotiated contract process. To the extent that we have to spend capital to support it, we certainly will expect to get a reasonable rate of return for those investments and would include that in our pricing. Okay. All right. John, a follow-on to something you were talking about. Becca Followill from U.S. Capital Advisors is saying, Do you see any other states adopting Low Carbon Fuel Standards over the next few years? It's just been proposed in New Mexico. You mentioned a few others. What is the magnitude of that opportunity, CapEx wise, on a national basis? Other states considering this, and then what do you think the magnitude of CapEx is? I mentioned too, Mid-Atlantic, you're hearing rumblings in many of the states there, New England, and all throughout the Northeast. We're extremely well-positioned in the New York Harbor and the Mid-Atlantic area. From a capital standpoint, the docks are already there, the rail's already there, the tanks are already there. Any CapEx would only be in the form of any type of additional piping that would be required in the facility to segregate the assets. Very minimal CapEx, and I think we're very well positioned to handle those products if that came to pass. Okay. Very good. Another one for you, John, from Caitlin Doldan at First Eagle Investment Management. Your perspective on why you think the terminals are so hard to replicate, your terminals position is so hard to replicate. Sure. Kim was referring specifically to Houston. The first answer is land. There's very little land available on the Houston Ship Channel. We use the term at the bottom more than just a bucket. Beyond that, it's the optionality. It's the inbound pipes. Many of the pipe corridors are 100% full there. Being able to access those refineries, those petrochemical complexes, Mont Belvieu, et cetera, for those cheap feedstocks. Yes, you could bring it in via truck, but a pipe is obviously a much more efficient option. The last piece is the docks. Nobody has the dock infrastructure that we have there with the 11 ship jacks and 55% upside on those without additional capital required. To be able to go in and find the land, build the tanks, get the connectivity, build out the dock infrastructure, be able to handle unit trains, be able to handle rail cars, would be all but impossible in this environment. We think we're very uniquely positioned there. Okay. Very good. A question from Keith Stanley. What are your expectations for investing capital to support the energy transition and the fuels of the future? Are you working on any material new projects? When would you expect this to become a more meaningful portion of the investment backlog? I'll start off with that. I think our backlog are those things that we view as very high probability and oftentimes are under contract or going through a permitting process and maybe even under construction. We add to those when they become very ripe. As you've heard a number of our team talk about, we have some nice opportunities with the facilities that we already have to do the add-on expansions as John was just talking about, building off on the footprint and doing so at attractive returns. Where the capital would start to get chunkier would be if there was some opportunity, for example, to do a significant carbon capture, but even if someone else was doing the capture, significant new pipeline build to move carbon and sequester it. New hydrogen facilities and infrastructure to support those, whether that's investments on the existing asset or some extension opportunity. I think, Keith, the right way to think about those things and those larger investments coming to pass is you really need to have something that gives you a price for these things. We've seen how that works with what Dax was talking about. When you have a price that you're shooting against in California, for example, on the Low Carbon Fuel Standard plus the RIN cost, and that shows you $3+ a gallon, well, then you've got something to work with in terms of what you're going to go out there and pursue and what might require capital investments. We would stick to our knitting here in terms of it being things that generate an attractive return and things that are very akin to what we already do and know how to do. You really need to start seeing some pricing. I think that pricing can show up in the form of the tax credits. It can show up in the, like Jesse talked about, on 45Q, or it can be in renewable portfolio standards where the investment by a utility customer of ours, for example, is going to be flowed through because the regulator is aiming for a certain amount of hydrogen in the mix, for example. I think that's the thing to watch for as the leading indicator is how are we seeing these things get priced. If you're asking in part whether we're likely to throw in on something that's more of a loss leader or a bet that it becomes economic a decade from now or something, that's not going to be the way we'll play. We're going to be disciplined about it, and we'll take those opportunities as they come, whether they're small build-offs of our existing network or whether they're big chunkier ones because we can see some real visibility to how we make a return on them. Okay. I have a question from Jean Ann Salisbury. Gas pipelines, so I guess this is for you, Tom. Again, is there enough overall capacity into the demand regions, California and New England, two very different markets, obviously, but California and New England, to support the illustrative increased gas needs on slide 26 as the renewables grow in market share? Could this drive new pipeline expansions? I'll add to that storage build over the next decade. I think the point you just made, Steve, is a critical one. Building, especially in New England, even out west, can be very problematic. I think when you partner existing pipeline capacity with market area storage, I think that will certainly provide additional capability to manage those intermittency issues that come up with growing renewable penetration. It'll be worth watching. We've certainly seen the challenges out west with the pace of that occurring. There may very well need to be some additional pipe infrastructure to help support this as well. We think storage and existing pipeline capability, especially with the pressure capabilities related to it, will certainly serve those markets well. Okay. Another question that we'll start with you on, Tom, and then I'll ask Dax if he has any additional commentary on it. This is from Ujwal at Bank of America. You mentioned the use of existing right of way for power transmission. Could you talk a little bit more about what the opportunity is for KMI there? Yeah. It's very early days. Certainly, we'd need to get a feel for what our right of way opportunities and what our agreements say. I think if you think about it fundamentally with the renewable density issue that we've been raising, as that penetration increases across the U.S., additional transmission lines will be necessary on top of just overall power demand needs as well. Utilizing our 70,000 miles of pipeline that serves really all the major markets at least at a high level, makes a lot of sense as an opportunity to potentially explore using that for the electrical power grid. All right, Tom. You didn't think building pipelines was hard enough, I guess. Right. All right. Dax, anything you want to add, looking at your network? Yeah. I agree with everything that Tom said. Tom mostly covered it. The one thing that I would augment what Tom said is that, in the products world, we have a lot of pipelines, a lot of infrastructure, and a lot of right of way in the state of California. California is number one, I think, on the leading edge of driving towards electrification. Number two is also front and center with respect to fire and other issues with above ground electrical wires and transmission lines. I think that is an important part of the conversation. Again, I think it's early days. Taking that into account, I think it's an important part of the conversation that could give us some wind at our backs in the conversation. Okay. Thank you. Question for James from Elvira at RBC. You've lowered costs by $100 million annually. Do you see additional opportunity to reduce costs? That's for you. I've got one for Dax as well. Go ahead. Yeah, as we get a little further into it, I believe there are some additional areas of efficiencies. I don't know if that it'll be on the order of $100 million, I still think there's some low-hanging fruit out here. Again, as we get further into operating in this mode, we'll be able to identify those and take advantage of it. Okay. All right. Thank you. For Dax, in your build-out of renewable diesel facilities in California? Does that drive incremental revenues or does that replace revenue lost from liquid hydrocarbons? No, it would be incremental. The hubs that we talked about would absolutely be incremental, and they would stand on their own. Those economics would not take into account the potential replacement of gasoline in the prorated lines where diesel came off of it. It would be purely incremental, and the projects would stand on their own. Okay. Last question for now from Elvira is on carbon capture and sequestration. Jesse, how big do you think that opportunity could be for KMI? It's very early days. Some of the customers that we are in discussions with, it could be as much as a 30%-40% increase in total volume. Again, these are prospective, very early days, you could add significant volume to your system. Okay. All right. Tom, a question for you from Michael Blum at Wells Fargo. What is the tone of the conversations that you're having with producers in the Haynesville? Do you expect drilling activity in that play is going to increase? Yeah, I think, we've seen good activity there, certainly in the latter stages of 2020. Expect that to continue in 2021, especially in our view as gas prices continue to increase. We think that'll be very supportive for the Haynesville, and again, it's geographically very strategic for Gulf Coast LNG exports. We do think that will certainly be a growth story for the industry. Our asset there is heavily dependent on one major producer who has not been focusing drilling efforts there in 2020, but we expect that they will in 2021. Okay. Another gas question from Jeremy Tonet at JP Morgan Securities. Tom, with the addition of PHP now pulling another two BCF east, do you see a negative impact on volumes flowing west on EPNG to California or other Western markets? If you do, does that offer any upside opportunities for their other systems which send volumes to the West Coast, in particular on Ruby, our systems, or particularly on Ruby, or is that not possible given the bifurcated market between the north and south? Does the shift on the West Coast away from that gas and to renewables limit demand pull growth overall from those markets? Starts with a question obviously about the pull from the Permian and what that means, and then also what the impacts are going to be on the dynamics in the California market, both from the Permian gas finding other outlets, as well as California relying more on renewables. I think I captured that about right. There's quite a few variables in play in answering this question. One, as you add more capacity eastbound to the market, that does create a little bit of lumpiness, more capacity versus existing production in the Permian, and we expect that to catch up and more and require ultimately, over the next several years, even incremental capacity than what is expected to go in. I think part of what we're seeing in the near term is just the increase of takeaway capacity eastbound versus existing production in that basin. Then coupled with that is some of the seasonality factors in the west for weather demand, reduced overall demand for a period of time on the West Coast. We think that's probably more seasonal in the near term or has been than consistent. In the longer term, clearly as renewable penetration increases, the actual volume on a 24-hour basis that flows to that market could go down. The capacity required to serve the intermittency of that demand goes up. As you pointed out earlier, we get paid, and will get paid, either for the capacity that we sell to serve that 24-hour capability, even if it's used less than that. If we've been changing our services, modifying our services to serve specifically that intermittency and expect to get at least the same value as we otherwise would, if not more, for the 24-hour service. As far as the northern versus southern California Ruby question, I think, the Rockies versus AECO spread really is the driving factor there. As long as Canadian supply is priced the way it is, that demand in Northern California is largely able to be served from Canada. For outages or shocks, whether it be weather shocks or fires and things that may shut down pipelines, I think Ruby volumes will stay similar with what they have been as of late. Okay. All right. The next question, it speaks to gas compression. Tom, you go first, I'm going to ask Dax to comment on it from a pump station standpoint, and John probably too, in terms of using excess land for renewables. Just starting with the question from Michael Blum, Wells Fargo, is there any opportunity to replace gas compression in the pipeline business to either electric or solar? We've done a lot of that, Tom, as you know. If so, on the electric side. If so, how much CapEx will KMI spend on this over the coming years, and what do you think the returns look like there? I'll start with Tom and then ask both Dax and John to comment as well. Yeah, I think it's really TBD. At the end of the day, we want to do the most economic thing here. We certainly are having conversations, as I mentioned earlier, of using clean power to reduce our gas costs or our energy costs, excuse me, and reducing emissions as a way to green up our footprint. At the end of the day, as far as spending incremental capital, I think the economics of the cost savings and/or selling excess power back into the grid, those will all have to kind of clear the capital of converting from gas to other sources. Okay. All right, John, why don't you go next? Same TBD. We had done one solar project up at our Staten Island facility, but as you know from the announcement, we sold that facility to a land developer this past year because of the New York spill tax regulations made it not competitive. We have since cataloged land available at each of our facilities, and we're looking at any type of projects, whether it's solar, wind, renewables projects, co-locating chemical manufacturers. We believe we're long on land across the board. Great places like Fairless Hills, our Seven Oaks facility on the Lower River, our facilities in the Chicago market, very close to end users. Long on land, long on infrastructure, should be opportunities to make further investments. Okay. Dax? Yeah, exact same. Most of our pump stations are power driven. Exact same as John and Tom. We've got in our business, we're long on land. We're certainly looking for opportunities, and we've had a number of conversations with both utilities as well as solar developers and other renewable developers on the ability to develop facilities that we can potentially power our assets with that generation, and then potentially sell back in the grid. In California, paradoxically, it's a little difficult because there's already been so much renewable development, and the load shaping and demand is already been firmly imprinted with what you see with renewables. We've seen a couple of potentials in the Southeast and exact same TBD, but we're engaged in conversations, and hopefully we can make something happen. Okay. Question for Jesse on the CO2 pipeline opportunity, really. Christine Cho at Barclays. You mentioned that gas and oil pipes would be difficult to retrofit for CO2, and so it would be new build, at least new build into new places. What would need to happen for these economics to make sense? From what kind of facilities does the carbon capture make the most sense? Are we talking about a lot of small diameter pipe or larger pipe? Thanks for the question. If you look at the slide 136 there, you can kind of see the cost structure on capturing carbon, CO2, from those different emission sources. Where we believe the market will evolve is where you have concentrated industrial areas, perhaps the Midwest. If you have that, then you have long-haul pipe that you'll have to get to a producing region in order to utilize it for people on. I think the answer's kind of twofold. I think you may have some small facilities with small diameter pipes, but eventually you'll have to have a major trunk line. They're doing studies in Wyoming now to develop infrastructure within the state, so we're discussing and keeping up to speed with any incentives that are going to be there. I think there will be governmental support, both on the regulatory side and from a financial incentive side. I think the market's going to evolve. It's going to evolve slowly because you're going to have to have scale. I know I'm not answering the question directly, I think there's going to be multiple projects. Ultimately, you're going to have to have a major trunk line in a concentrated area. Okay, thank you. I can see we're not going to quite get to all these questions, again, I'll remind everybody, we do have our regular Q&A session at the end of the presentations, feel free to come back with these. Tom, another question from Christine at Barclays. As you think about the possible need for another gas pipe out of the Permian a couple of years down the line, what are your thoughts about converting one of the industry's existing crude pipes to gas service, given the excess capacity on that side? Yeah, I think it's certainly something to look at. It's going to get harder and harder to build new pipeline, for one thing. I think to the extent there's, whether we or others have underutilized assets. It brings the best economics to bear on an incremental capacity to the market. Certainly would be something we'd look at. Okay, very good. All right. Let's try to get one more in. Jesse, a question from Becca Followill, U.S. Capital Advisors. Does Oxy's initiative on direct carbon capture in the Permian, and other E&Ps looking into it, threaten your CO2 pipeline business over the long term? I think if you go back to slide 136 there, you can see that direct air capture, it doesn't meet the scale there. There's a lot more economic sources of capture. Direct air capture is upwards of $1,000 a ton. I think Steve mentioned on the call last week. It's 0.04% of the atmosphere. It's not a question of can you suck it out of the air. I think it's a question of can you do it economically. I think, if you can solve for the economics, certainly it's a threat long term. We see it as a very small percentage of success in that area. To answer your question, long term, if the costs can come down materially, advances in technology shrink, certainly. We don't see that in 10 years. Okay. All right. Okay. I think that concludes the time that we have for the business unit panel. With that, I will turn it over to David Michels, our CFO. All right. Thank you, Steve. I'll go through our 2021 budget, and this is consistent with the summary guidance that we provided in December, but just with a lot more detail. As usual, we've posted this to our website, and we're going to compare back to it throughout the year so you can all see how we're progressing. Here on slide 65, here's the overview. The budget to generate $2.1 billion of net income, up $2 billion from 2020. $6.8 billion of EBITDA, 2% lower than last year, $4.4 billion of distributable cash flow down 3%, $800 million in growth CapEx and contributions to JVs. Expect to declare dividends of $1.08 per share, up 3% from the $1.05 we declared for 2020. Expect to end the year with a debt to EBITDA ratio of 4.6x, which is flat with where we ended 2020. This will be, as Kim mentioned, our sixth year in a row with no need to access the equity market with our operating cash flow, more than covering all of our projected cash flow needs, including our dividends, our sustaining and growth CapEx. In fact, as we've stated previously, we expect to generate $1.2 billion of DCF in excess of our CapEx and dividends. It's based on that strong cash flow profile that we have stated that we have the capacity for up to $450 million of opportunistic share buybacks. We don't have any buybacks assumed in the 2021 budget, we have the capacity for them. All right, moving to slide 66. This EBITDA bridge shows 2019 to 2020 actual, then to 2021 with the main puts and takes called out. The slide illustrates just how stable our underlying business really is. It's even hard to tell that we experienced a global pandemic and a worldwide oil price war during 2020 just by looking at the slide, especially when you take into account that we had a large reduction of contribution in 2020 due to our sale of KML and Cochin assets. That's that 0.2 sliver there, that blue sliver that you can see on the left. In fact, that's the largest single unfavorable category in 2020. The main categories, the other categories that are called out in 2020 aren't going to be surprising. They're consistent with the communication that we provided during 2020. For 2021, we'll cover these in the upcoming pages. As you can see, the two largest moving pieces are increased contributions from our growth capital projects and lower contributions from contract renewals, which we've been calling out for a few years. All right, moving to slide 67, assumptions and highlights. Natural Gas segment is expected to be down a little from 2020, largely due to those unfavorable recontracting impacts. Those are mostly at FEP and Ruby, among others, those are the two biggest, we've been disclosing these exposures for years. Looking forward a little bit on that front, we have a full year impact coming from Ruby's recontracting for 2022, as most of those contracts are being rolled over in mid-year 2021. The impact overall to the company from these recontracting exposures for the company will be much lower in 2021, in 2023, they'll be much lower still. We have a slide in the back that covers that. These are partially offset in 2021. These recontracting impacts are partially offset by growth project contributions in the Natural Gas segment, the largest of which is PHP, which we recently placed in service. We also see growth in Natural Gas due to increased volumes and margins on our Texas intrastate systems. We expect some lower volumes on KinderHawk and some lower rates on South Texas and North Texas G&P assets. In the products segment, we have a nice uptick here. This is driven by the refined product volume recovery, up 15% from 2020 across all of our refined product assets. To reiterate a little of what Kim covered earlier, we expect our gasoline and diesel volumes to average 2% below 2019, and that ramps up over the year. 4% off 2019 in Q1, flat by Q4. Jet fuel volumes to average 14% below 2019, much lower in the first quarter and recovering quite nicely in the fourth quarter. Very good recovery expected in all of our products there, particularly the road fuels. We also don't expect some of the unfavorable oil price impacts that we experienced in 2020 to reoccur in 2021. We expect to see some rate improvement from the FERC index escalator, and we have some lower contributions from KMCC and Double H due to some recontracting there. Terminals is up due to the volume recovery with overall liquids volumes expected to improve 20%. That's driven by our refined products volumes, but we also have good growth in biodiesel and ethanol, just as John touched on earlier. We've got a good position there. Bulk volumes are also expected to improve 16% from last year. Contract escalations and some expansion project contributions also add to the growth in the terminal segment. Partially offsetting those are the foregone contributions from our Watco sale in Q4 of last year and lower contributions from our Jones Act vessels. CO2 segment is down, and that's due to lower expected realized oil prices. Here, it's not due to the spot WTI price, it's due to our average hedged per barrel price. It's about $5 per barrel lower in 2021 versus 2020. Additionally, we expect net oil production to be down 14% from 2020. SACROC and Yates are down 11%. Tall Cotton, Katz, Goldsmith, our smaller fields are down 29% as we're not deploying additional development capital in those fields. We also expect lower CO2 demand to drive those sales volumes down 24%, and all of that is partially offset by some lower OpEx. The two final bullets here, you can see that we are budgeting three-month LIBOR to be 21 basis points for the year. That's down from an average of 70 basis points for 2020. It's a nice improvement there. Once again, KMI does not expect to have any material federal income cash taxes. All right, slide 68. You can see here the main differences between DCF and earnings. DCF and net income are really two items, as usual. Our DCF includes cash taxes instead of book taxes. Our DCF includes sustaining CapEx instead of booked depreciation. As most of you already know, our sustaining capital is the capital that we believe is required to maintain our assets in good working condition, or in other words, a cash proxy for asset depreciation. There are a few other moving pieces. Those are the two largest differences. A fairly straightforward approach to arrive at our DCF. Moving on to the per share metrics. Same slide. Yeah. Our adjusted EPS of $0.92 is $0.04 above 2020, that's because the adjusted EPS excludes the large certain items we took in 2020. 2021 DCF per share is $1.95, down $0.07 from the $2.02 we generated in 2020. As has been mentioned, we expect to generate very significant coverage, almost $2 billion in DCF coverage for 2021, that's after the expected 3% increase in our 2021 declared dividend. All right, going on to the adjusted EBITDA. All right. Natural gas and CO2 are lower. Products and terminals are higher, that's due to the items that we covered on the assumptions page. Overall, segment EBITDA across the company is about flat. Our G&A here, our expenses are higher, that's mostly due to lower capitalized G&A, we also have some higher benefit costs and higher non-cash pension expenses, which more than offset the cost savings that we achieved from our organizational efficiency project. Another note on the organizational efficiency project cost savings. About half of those cost savings hit here in corporate G&A. About half are picked up in the business units, they're already incorporated in the segment EBITDA numbers. JV DD&A, the lower $30 million, is driven by less DD&A being added back from Ruby, which is related to the unfavorable recontracting on that pipe. Those are the main moving pieces to get to adjusted EBITDA, down 2% from 2020. Our interest expense is a favorable $95 million. That's due to our lower debt balance from paying off debt with operating cash flow, cash on hand, proceeds from KML and Cochin, those sales. Sustaining capital, we expect will be higher by $134 million. We'll cover that on a later slide. Other items. Here, this is where the higher non-cash pension expenses are added back. It's a positive variance here. We have some lower required cash pension contributions for 2021. Those are the main moving pieces to get to DCF. The next slide will cover CapEx. Sustaining CapEx up $134 million from 2020. Natural gas is the largest piece there, up $83 million. That's driven largely by additional pipeline integrity work, as well as class change projects, mostly on TGP. We're also seeing large additional costs to comply with the PHMSA Mega Rule being phased in, which adds incrementally to our pipeline integrity costs. Terminals is also up $44 million. A little more than half of that is from deferred projects from 2020. The remaining covers a number of projects, one of the larger ones is an increase in, or includes a warehouse replacement project at Pinney Dock. Discretionary capital, we're budgeting to spend about $800 million in 2021, mostly in the natural gas segment. Overall, we're down about $900 million from 2020, mostly due to less natural gas midstream spending, much of which is related to the PHP project coming online. All of the capital projects that we have in 2021 are relatively small. We don't plan to spend any more than $70 million on any single project in 2021, and we expect to spend below $20 million on most projects. While the smaller projects don't move the needle as much, they do tend to come with very nice returns, especially relative to the larger, higher profile projects. This is a highly effective capital program. Down below discretionary capital, you can see we show a reconciliation to GAAP CapEx. This is a new item we're including. The main reconciling items are adding back sustaining capital, as that's not separated from growth CapEx on the cash flow statement. We also remove our share of JV sustaining capital and our contributions to JVs, as those are not included in GAAP CapEx. We hope that's useful to those of you who are looking to understand the main differences between our discretionary capital and GAAP CapEx. All right, slide 71, DCF self-funding. This is the way we tend to track our ability to fund capital and dividends. As we stated in the 2021 budget guidance, we expect to generate almost $1.2 billion in DCF in excess of our capital and dividends, up $725 million from 2020. We think this is a pretty decent way for investors to see just how significant our cash flow generation is without some of the bucketing issues that you may experience by using the GAAP cash flow statement. With that being said, on slide 72, we do show free cash flow from beginning with CFFO. You can see this walks from net income down to cash flow from operations. We deduct the GAAP CapEx number to arrive at free cash flow. You can see the free cash flow is expected to be up $400 million from 2020, and then we further subtract out dividends paid to arrive at free cash flow after dividends. That's the figure that's most comparable to our DCF after CapEx and dividends. The single largest variance between that figure and this one is the fact that almost $250 million of distributions we receive from JVs is captured in the investing section of the cash flow statement instead of the operating section. That's obviously cash flow to us. It just happens to fall outside of CFFO. We see that on the next slide, on slide 73 in our sources and uses. You can see this is a high-level summary of our sources and uses for the year. Starting with uses, $2.4 billion of dividends expected to be paid. We have debt maturing of about $2.4 billion. There's the $1.35 billion of CapEx. Then we expect to make $114 million of contributions to joint ventures. On the sources side, we have our $4.6 billion of CFFO. At the bottom of that table, you can see the $245 million of distributions we received from JVs that are captured in the investing section of the cash flow statement. Taking those two items, combining it with the cash balance that we had at the beginning of the year of about $1.2 billion, you can see we nearly completely cover all of our expected cash uses with just about $300 million of borrowings needed for the year. Very strong liquidity position, healthy financial position to be in. Despite a relatively small amount of potential funding, we also recognize that the interest rate environment remains very attractive and we may want to take advantage of it, just like we did during 2020, which led to the very large cash balance that we had at the end of the year. All that being said, we do have plenty of capacity on a revolver and can be patient. All right. Slide 74. As I mentioned, we expect to end the year at 4.6x debt to EBITDA, which is in line with 2020, as well as our long-term leverage target of about 4.5x. We have a very strong liquidity position, $1.2 billion of cash on hand at the beginning of the year, $4 billion undrawn credit facility, and expect to generate the $1.2 billion of DCF after CapEx and dividends. We've already paid off $750 million of this year's maturing debt, which leaves us with just $1.65 billion for the rest of the year. You can also see on this page that we've done a nice job reducing the average rate for much of our long-term debt with the next several years below 5% for coupon rates on average. With that being said, the current market offers even more opportunity to improve on these rates. All right, slide 75. We'll go into the quarterly profile. As we've mentioned in prior years, our yearly results are not evenly distributed. The main drivers are seasonality in our gas pipelines segment. Which are bolstered in Q1 and Q4 by strong winter demand and capacity utilization. DCF is further impacted by tax payments, which are focused in the second quarter, and lower sustaining capital expected spend in Q1 versus the rest of the year. As usual, we would expect our first and fourth quarters to generate the highest contributions, followed by the second and third quarters. Slide 76 is our cash tax calculation slide. As you can see, we expect to generate a taxable loss for 2021 of over $1 billion, mostly due to tax depreciation. Once again, don't expect to owe federal cash taxes this year. Additionally, given the large net operating loss balance to which this $1 billion is adding, we don't expect to be a material cash taxpayer until beyond 2026. The $79 million of cash taxes in our 2021 budget shown here are mostly for our share of taxes at Plantation and Citrus, which are C Corp joint ventures. Slide 77 shows our budget sensitivities, this page is for your reference, but I will hit on a couple of these. You'll see that our commodity price sensitivity is quite low after taking into account our hedges. Just $3.4 million for each $1. That's $3.4 million impact to our DCF for each $1 per barrel change in the price of oil and just $400,000 for each $0.10 move in the price of natural gas. We've also included sensitivities here for movements in our refined products, natural gas, and crude and condensate throughput. We generally expect a recovery in demand for those products. The shape of that recovery is still uncertain, so these sensitivities have been provided once again for you all to understand the magnitude of contribution for each of the assumptions provided. All right. Slide 78. To wrap up the 2021 budget section. As Kim mentioned, we really weathered 2020 well. We did miss our EBITDA budget, but only by 8%, despite one of the most disruptive years any of us have seen. We comfortably increased our dividend by 5%, reduced our debt by $990 million, increased our free cash flow by $365 million, and we issued a company record low coupon rate debt for both 10-year and 30-year bonds. I would say in many ways, we are in better financial shape today than we were a year ago. For 2021, we expect some similar improvements in our dividend with an expected 3% increase, further reduction in net debt of $800 million, and a further increase in our free cash flow of $400 million. As has been mentioned, we also have the strength of cash flow to consider up to $450 million of share buybacks, should the opportunity present itself. Based on what we experienced during 2020, this is really outstanding financial performance and a good projection for 2021. I think it's a product of outstanding performance by our operating and management teams and also demonstrates, I think, the stability of our assets and our business model. With that completes the 2021 budget section, and we'll transition into Q&A. Okay, very good. Again, as a reminder, the registered participants, you should have a dialogue box at the bottom of the slide. We have a number of questions we'll start going through, but that's where you would enter your question. I will start with, there's a question on M&A. Kim, Michael Blum is asking, what is your appetite to do M&A to expand your carbon capture or renewable fuels business? Sure. I think we will look at those opportunities. It's something we continually evaluate is not only expansion opportunities, but M&A opportunities. As we've talked about, we have a couple of very key criteria as to whether M&A is going to work. One, it's got to be neutral to our balance sheet. Two, it's got to be DCF accretive. Three, it has to fit our strategy. Meaning, it's generally going to need to be a fee-for-service business. First, it has to pass those thresholds, I think. The renewables market right now is heated up. There's a lot of frenzy out there, a lot of these companies are expensive. I think that given our criteria, combined with the market right now, I think it makes it unlikely that we will find good opportunities. We will look. We will not let that stone go unturned. Okay. Kim, a follow-on question that's M&A related from Pearce Hammond at Simmons. Do you think due to regulatory pressures, combined with investor interest in renewables, do you expect to see more gas utilities divesting their pipelines similar to Dominion last year? If so, is that an opportunity for us? Sure. I think there is the possibility that more come to market. Again, it's something that we are going to look at. As we've said, we think the natural gas business has a very long runway. You also have the potential that you can handle the other products on the pipelines, renewable natural gas and hydrogen. We think there's a bright future there. Whether it's storage or natural gas pipelines, those are obviously something to consider. Again, it's going to need to meet the criteria that it's got to be neutral to the debt metric, needs to be accretive to DCF, and obviously, natural gas pipelines and storage fit our criteria, so that criteria would already be met. I think, if we can get things at the right price, then it's something that we're absolutely willing to pursue. Okay. All right. A question from Jeremy on DAPL. A lot of headlines floating around on DAPL. Given the gathering and crude pipe systems you have in the basin, how are you thinking about competing impacts to your systems from a potential DAPL shutdown? I will start just by, this is a question that's not asked, but there's just been some confusion on it in the past, I want to make a point of distinction here. People have asked about, and there has been some confusion about any implications on PHP, for example. We're not operating there under a federal easement. That's an important distinction. We're operating under the Nationwide Permit 12 permitting program for the Army Corps. That's a permitting program that's important for construction activities, water body crossings in particular. It governs construction. It does not govern ongoing operations. That's an important point of distinction between us and DAPL. Having said all that, really the question relates, Dax, to impact on our business in the Bakken on the crude side. I'll turn that to you. Yeah, thanks. Jeremy, thanks. Good question. As I said on the earnings call related to a similar question, certainly don't want to speculate on what may or may not happen to DAPL. We obviously got a ruling out of the D.C. Circuit last couple of days. I'm not sure that the ruling that came out is really inconsistent with what the market had already been assuming and thinking about since for the last few months. Certainly, anything happening dispositive to DAPL would be a positive for Double H. I think taking away substantial incremental egress out of the basin would be a negative for production in the basin. Having said that, tying it back to my comment about I'm not sure much has changed. We're in pretty constant communication with our shippers up there about their drilling plans and what they're planning to do. Just looking at over what we've received from them in the past three months, the number of well connects that we're expecting and what's been communicated to us has actually increased. We're looking to be kind of right on budget as things sit right now for this year, based on those communications. Looking at Double H specifically, we've got 31,000 barrels a day of third-party contracts and 35,000 contracted with our affiliate. Remember, it's a common carrier pipeline, so having a contract doesn't guarantee space on it. Space is guaranteed by shipping history. We are absolutely seeing, as I said on the earnings call, we are seeing our shippers value incremental egress capacity, and people are nomming. The pipe is looking to be close to right at full for February. In terms of how we play it, again, I think that we obviously like long-term capacity contracts. Anything that happens would be a positive to Double H. If Double H filled up, as you know, we do have a potential expansion capacity right now is right about 88 a day. We do have the ability to expand it up to roughly 120, 130 a day. We've got that expansion on the shelf, and we certainly would look to go talk to people if the opportunity presents itself. Okay. All right. The next question, Spiro Dounis at Credit Suisse. What data points or anecdotal evidence are you relying on to inform your budget reaching normal or near normal levels of refined product demand by year-end? It's tough to forecast in this environment, but curious if you are seeing green shoots anywhere. I'll call on John in a second to talk about the green shoots. The way we put the budget together is we looked at the EIA projection for refined product demand in 2021, and we got, I think, a couple of percentage points more optimistic than what the EIA outlook was. We reduced our expectation certainly below 2019 levels on jet fuel, for example. We did make some distinctions between them. In some, we did partly shape that expectation of getting to near normal. In one instance, we probably just flatlined it. There may be a little bit of noise here from quarter to quarter. We are starting to see some green shoots. Obviously, the pandemic has stretched into, and the shutdowns have stretched into the early part of the year, and so refined products volumes have remained lower than a normal run rate for sure. We are starting to see some green shoots. John Schlosser, you want to talk a little bit about that? Sure. As we mentioned, and I'll caveat this by saying, most of our businesses take or pay, most of it's MVC-based, so it doesn't have as significant as impact on us as it does on the products pipeline side. We saw a pretty significant demand decline early on to the tune of about 25%, 21%, and then 9% in Q4. Again, the impact of that on the bottom line was only $11.4 million in Q4. We started with the premise, what is the new norm? We arrived at going back to 2019 original numbers, and we put together our budgets. We ratcheted that down, as Kim mentioned, 4%, 3%, and 2%. We ratcheted our petcoke down 2%, and we ratcheted our coal assumptions down, and then layered on known expansions to that. We're seeing volumetrically improvement in each of the months that we've had. In talking to the customers, looking at the EIA and Platts, I think most of them are fairly optimistic that there will be some type of return to normal. The question is, what is the slope and how close do we get back to the original numbers? We guessed at that. We thought it seemed reasonable, but only time will tell how close we are to that. Just back to the sensitivity that David put up there. If we're off by 5%, it has a negative impact on the terminal side of $9 million. Okay. All right. The next one is from Bank of America. Kim, the question is: how has our strategy evolved around return thresholds for organic or inorganic growth projects by business segments? When you think about ESG-oriented investments, would you be comfortable with lower project returns? Do you think KMI can take advantage of the lower cost of capital that's afforded to zero emission energy infrastructure in the market today? Yeah, we haven't changed our return thresholds. Our return thresholds, as I mentioned earlier, has been about 15% unlevered after tax on average. For investments that have long-term take-or-pay contracts with good creditworthy counterparties for then, we would be willing to do something less than the 15%. On the other hand, if it's a gathering and processing asset where you've got some volume risk, and/or potentially any price risk on the CO2 production, where you have some volume and price risk there, we're going to require higher than the 15%. We are looking at renewable investments, as we've talked about all throughout this presentation. To date, we have found that the renewable investments that we're looking to make meet those thresholds. When we look on the renewable diesel sides, primarily, where we found some opportunities, they would meet our return thresholds. We will look at things below our return thresholds. I don't think it's likely that we do a lot below our return thresholds. I think we want to make sure that we're informed about the market, and is there the chance that we do something slightly below where we would have done before? Maybe in a select instance, but I don't think it's going to be significantly below our current return thresholds. I guess maybe something slightly below our current return thresholds, very selective. Unlikely. We're not going to change the return thresholds, and it's unlikely that we do much on the renewable space that's going to be inconsistent with our current return thresholds. Hey, Steve, I think you're on mute. My apologies. It was bound to happen. We had a side bet on who was going to screw it up, and I've now lost, so. Kyle May, Capital One Securities. David Michels, can you talk about your philosophy on shareholder returns and how you think about dividend growth versus share repurchases or other options available? Yeah, sure. We have a bias towards returning value to shareholders. We want to make sure that dividend level is sustainable and is very well covered. We think that the $1.05 decision for 2020 achieved that. We think this expectation to declare $1.08 achieves that for 2021. Beyond that, we'll continue to look at our balance sheet, our projected cash flow projections, free cash flow, to identify if we have additional cash flow for potential returning value to shareholders. The benefit of potential buybacks is it's not as non-discretionary as a dividend. We don't want to mess with the dividend levels that we're at. We think the dollar rate is appropriate. Beyond that, I think for 2021, we've talked about the cash flow capacity for up to $450 of share buybacks. We think that would be appropriate if the opportunity presents itself. Steve's mentioned this before, it would be based on high level, based on what our balance sheet looks like for 2021, and where our share price is. We're not going to be completely agnostic to the share price in making the determination on buying back shares. Okay. Now, David, why don't you keep going on this next one from Ram Vadali at DBRS. How has your counterparty risk experience so far, and how are you addressing rising counterparty risk? Yeah, that's a good question. 2020, we saw a lot of stress in the industry. We had over 20 of our counterparties file for bankruptcy. Because of the value that our assets and our services provide our counterparties, however, very few of those rejected their contracts and their services with us. In fact, only two of those really generated any DCF impact to us. For full year 2020, the impact to us from counterparties who filed for bankruptcy was about $40 million of an impact. This is in one of the most disruptive years that the energy space has seen. Prior to that, 2016 was our peak in terms of DCF impact from counterparties filing for bankruptcy, and that was about $10 million of DCF. It definitely was a new high watermark in terms of impact to us. From this point forward, we continue to keep a very vigilant eye on the collateral requirements from our counterparties, make sure that they are posting the collateral that's required, that is our right to require from them. Our counterparties have been very good at putting that collateral up. We have a significant amount from those who are in a stressed position. I would also say that as of right now, when we look at our at-risk counterparties relative to looking at that list throughout the year in 2020, we're in much better shape. I don't think it's getting worse. I think it's getting better going into 2021. I think this page speaks to it. 1% exposure from B- or below rated customers. I would say when we really take a look at who's at risk and how much exposure we have from them after looking at the collateral that they've posted with us and the remarketability of the assets that they are contracted on with us, we're in very good shape relative to where we were in 2020. Okay. I have another question from Spiro. What are your thoughts on expanding internationally? Not talking about Canada, but more along the lines of developing countries in Central and South America. Refiners are developing terminals abroad. LNG companies are creating markets for natural gas. The total addressable market opportunity seems large, and the core competencies should fit well with KMI. This is something I would say you don't say never to, but there are some fairly significant differences, clearly, in taking on a different commercial culture, a different regulatory and political regime, et cetera, when you invest abroad. I think what we've found and what I think we've been very successful at in Tom's business, we have great LNG customers, and those customers are very sophisticated about finding their way into those global markets and penetrating them. We've been doing our best to position ourselves as a preferred provider to those customers when it comes to their natural gas transportation and storage needs. That's been a very successful way for us to participate in the overall global story around natural gas. A similar situation in Mexico. While we do have one pipeline in Mexico, it's tied into end users down there. For the most part, we serve Mexico at the border, and we serve under U.S. contracts, U.S. law, U.S. commercial terms, et cetera. That's been a very low risk and very lucrative way for us to participate in that dynamic. In John's business, we participate in the global refined products market by enabling our customers to use our ship docks and our tanks. We've invested a lot in the dock space we have there, in the loading rates, et cetera, that lets our clients participate in that market. We collect a fee on our U.S. assets to participate in that opportunity. I think that's really center of the fairway for us and where you're likely to see us continue to participate. Again, I started by saying you never say never at the right returns and the right fit with capabilities, et cetera. It's a challenging screen to fit everything through. Okay. A follow-up question from Shneur at UBS. As David noticed on recontracting exposure, we've had a multiple-year cycle of revenue step downs due to recontracting natural gas. You show the step down in 2022 and a further, I'll point out, smaller in 2023. Has this cycle paused for several years? Have all big contracts from years ago now been recontracted at new levels? If so, what are the next maturities, and are they above market or currently at market? Look, the slide itself answers a lot of these questions. You can see the numbers there. Stated in terms of 2021 budget, 2%. For 2022 and 1% for 2021. There you see the answer on the last part of the question, which is that includes some Copano South Texas legacy contracts, whereas we pointed out that Eagle Ford has been particularly difficult. We do expect that we're behind most of those headwinds, and really, the phenomenon you're pointing to there is that there were a number of pipelines that were built out in the 10 or 12 years ago, that we've been working our way through, and FEP and Ruby are the ones that remain there, and we're reflecting those adjustments here. As we point out on this slide, and I think generally the expectation would be there's going to be other opportunities that help us offset these as our network fills up and as we have more business being done, more throughput associated with natural gas on our system. Again, we continue to quantify this for our investors. We're getting to the end of the line here. You see that, I think, in the numbers, and you see what remains in terms of contracts that we're dealing with and how we hope to offset it. Let's see. Another question from Kyle May at Capital One. This is for Tom. You've talked about the potential for developing another pipeline out of the Permian. Given the shifts that we're seeing under the new administration, what are your thoughts about the viability or challenges in developing such a pipeline, that is another pipeline out of the Permian, Tom? It's certainly going to be challenging. I think we'll be very cautious, very prudent in our approach there. We certainly will want to make sure we get appropriate returns for the risk involved in it. I suspect it'll be a longer duration project for construction and in-service than what we have done on the other projects. I think to the question that was asked earlier, it certainly will lend itself to looking at are there pipes that are underutilized and other sources or other uses that may make sense to not have it be a full greenfield pipeline project. I think that will help improve the execution of a project like that. Okay. We'll also echo what we pointed out before, which is a lot of the infrastructure development that we see coming and a lot of the demand that we see developing is really in Texas and Louisiana, where the permitting process is more straightforward. If the pipeline out of the Permian is a Texas pipeline, as our last two have been, we need to see what happens with the nationwide permitting process. Generally, it's not a FERC 7c certificated project. It's not under that same rubric, it's a fundamentally different outlook from permitting when you're talking about a pipe that's wholly within the state of Texas. Would we potentially be using a Nationwide Permit 12 as we have in the past, or would we be going for individual crossing authorizations, which, to Tom's point, might extend the time, but shouldn't render us unable to build it. The next pipeline, natural expansion out of it, unless we're using an existing infrastructure, does not involve going through the Texas Hill Country. It would more likely involve going north, a different environment there as well. This is probably as good a time as any also to comment on, there are a number of things that have been coming out of the new administration as they're putting pauses on additional leasing, for example, and that sort of thing. There's a lot to play out there, clearly, in terms of what the details of that are. As we've looked at that and examined it in the past when this is not the first time people have been talking about fracking bans. This is something that we've been evaluating. We did an analysis back in the third quarter. Our view of it was that it's likely to have an impact on growth, assuming people can drill on the existing leases they have, the ones that have already been let, and where people have built up a bit of a backlog. We see it as being an impact on growth, so maybe it has a negative impact of, call it 1 BCF-2 BCF on the growth that we would otherwise see by 2025. That changes if it goes deeper than that, and I think you'll see different numbers quoted out there. The one thing I want to point out about how we did the analysis, how Tom's team really did the analysis, is that we looked at what would be the net impact once you take into account the move from federally leased lands to available private lands. It becomes a net number. It's mitigated by that. If you presume that people are drilling in the most advantageous economic places, then it will have some impact. But the impact is definitely mitigated and muted to the extent that people look to move to their private land opportunities. That's not really part of the question, but that's certainly a topical thing as we're evaluating the impact on our customers primarily, but certainly indirectly on us of what we're seeing here out of the current administration. Okay. Question from Keith Stanley of Wolfe. CO2, aside from carbon capture, with commodity prices now higher, are you seeing more opportunities to invest in the EOR business at attractive returns, or are you less inclined to keep investing in that traditional EOR business? Not less inclined. Jesse, why don't you talk about what you're seeing? Certainly with the improved pricing you'll see in the slide with our SACROC long-range outlook. You'll see that the low pricing scenario of last year has shifted everything to the right. We're seeing economic projects primarily at SACROC and Yates. We've added those to the backlog. We are seeing the marginal projects cross the hurdle at these prices. We are seeing that. That's the comment I have for the incremental. Okay. Thank you. David Michels, a question for you from Michael Lapides, Goldman Sachs, on leverage levels. Do the agencies seem comfortable with your long-term leverage target, and what could drive you to lower that leverage target level, a less leverage level than where you sit today? Are the agencies comfortable, and what would make you want to drive the leverage down further? Right. We believe they are. We won't speak for them, but we believe they are comfortable with our long-term leverage target levels. We've had that long-term leverage target out there for years. We've been upgraded by the rating agencies and reaffirmed by the rating agencies since. We're on stable outlook as recently as December from Moody's. We think that they are comfortable with the longer-term leverage target. To go lower, we'll evaluate it if it provides a material benefit to our cost of capital. For the last few years, it really doesn't appear like it would create a significant improvement in our cost of capital. Don't see a great deal of benefit from going lower. We feel like it's the appropriate long-term leverage target at this time. Okay. All right. Tristan Richardson of Truist Securities. You noted on the biofuel side that U.S. is going to require $10 billion approximately of infrastructure spend through 2030. I think that was an annual number. What portion of this would KMI participate? Do you see KMI being a meaningful portion of that capital deployment? Acknowledging the inclusion of the $90 million California project you noted. Dax, I'll ask you to speak to this, and I do suspect that a lot of that capital is associated with the production of the renewable diesel, for example. I mentioned that as one of the kind of further step-out items, something that we would look at and evaluate if it were economic. Dax spoke specifically to our midstream participation, and so Dax, I'll turn it to you. Yeah, no, that's right. A lot of it obviously depends upon what the incremental credits are back to the earlier conversation about incremental low standards in states. Other states, I think, certainly that would benefit us that I think are considering these are Oregon, Nevada, and Arizona. On the diesel side, I think the U.S. uses about 3 million barrels a day of diesel. Clearly there's a lot more. California, I think, uses about 250,000 barrels a day. Right now, I think California's consumption of renewable diesel is something in the neighborhood of 55,000 barrels a day. There's a lot of room to move. One thing I think, though, that's important to keep in mind is that the feedstock for renewable diesel is not nearly as abundant as crude oil for hydrocarbon diesel. People that make it compete for it. Being illiquid, it obviously is subject to a lot of volatility. I think that the key driver will be incremental adoption of blending credits across the country by other states. With respect to other potential opportunities, I think that generally an advantage is going to go to a refinery that has an existing hydrotreater or renewable diesel. We certainly obviously have experience building a splitter. We've got Galena Park right across from our facility there. We've got a 100,000-barrel-a-day condensate splitter that we built and that we operate, and we've got some additional land there, and we've got the capability to be able to operate it. That's another type of step out that certainly we will be looking at that it's a little further afield than tanks and pipelines, but it's certainly something that we're capable of doing and we'll be looking at to see if it makes sense. Okay. To use another concrete example, John Schlosser, you want to talk about the ethanol hub that you've developed at Argo and your investment there? Sure. As I mentioned, it is the CME price point. We are the largest handler of ethanol between Dax's group and our terminaling group in the U.S. We're one of the largest handlers of bio and renewable, and we're one of the largest handlers of the feedstocks that are important in this process. We had a big project this past year where we expanded that Argo hub based on the demands of our customers. It was a significant portion, and if you look forward, a lot of what we're discussing revolves around these renewables. Steve may or may not have mentioned earlier, but we stood up a team internally under Kevin Grahmann, who is looking across the board at renewables, and within our group, we have a team that is doing nothing but talking to these customers that are looking at expanding and looking for infrastructure improvements. The order of magnitude, if you look at our shadow backlog, it's somewhere between a third and a half of the discussions that we have going on today. All right. In the time remaining, I think we can cover two. I'm going to pick the two that we haven't answered, at least in part already. Kim, for you, Michael Blum from Wells Fargo, expanding on his earlier question, what is the general appetite you have to do M&A to try to augment the growth opportunities in your traditional hydrocarbon businesses? Sure. Again, we're going to look at the same criteria that we do for everything, which as I mentioned is neutral, and hopefully accretive to our debt metrics. If it's, if you're saying our existing business, it already fits our strategy and then obviously it needs to be DCF accretive. The way that I would think about acquisitions of businesses where you potentially have some longer-term risk is we will look at that in the cash flows that we underwrite. We've done that in places where we've made new investments in businesses where we think demand may decline over time. We do that by reducing cash flows over time. If it's a volumetric cash flow, we do it by decreasing the renewal rate where we think we can renew a contract after it expires in five or 10 or 15 years. We do that by looking at lower terminal values. I think if it's in our traditional business, and we think there is some impact on demand, and that's not always the case, let me say that. I mean, some of our natural gas businesses, we may not see impact for 30 years. In other businesses where you might have a more near-term impact on demand, we try to take that into account in the cash flows and the terminal value that we underwrite. On the natural gas side, even though we may see a long-term outlook, to the extent that we think we might get a lower price on renewal because it's a supply push, and that basin may reduce over time, or we think there's significant infrastructure that's going to be competing with us, then obviously we try to take that into account in our renewal rates. Okay, one last question from Spiro Dounis at Credit Suisse. Talked about our mandate is invest in capital to create value. Capital discipline is something investors want and something you're delivering on. However, one of the most common pushbacks we receive on KMI are the prospects for growth or lack thereof. How do you think about balancing capital discipline against the optics that EBITDA could be flat or declining for the near or medium term? A good question. We look at our capital investment opportunities, as you imply, that we expect a capital that is our investors' capital, that we're going to deploy that at attractive returns. We're not going to deploy it at subpar returns just to be investing it to try to create some EBITDA growth. We want it to clear and well clear our weighted average cost of capital, and have confidence around that. That's the way we invest. The way we run our business is to be safe, efficient and reliable operators, to fully price our services, extract the full value for the assets that we have, for the network we have. I think what you've heard from all of us today is that we have a great network, and that network is going to serve our markets and our customers very well in the current environment, continue to serve them very well. It has opportunities in the businesses that we're serving today. It also is nicely positioned for the energy transition as it's evolving. We're doing some of that today. There's the opportunity to do more of it as time goes on, but we will be disciplined about it. We will invest capital wisely, and we'll run our businesses for safety, efficiency, and reliability, and we'll fully price our services to our customers to extract the most value that we can for our investors. I want to thank everybody for participating in our virtual conference. We all fervently hope to see you back at The DoubleTree next year in person. We look forward to that. Everybody have a great rest of the day. Thank you.