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

Okay. If we could take your seats, please. We'll get started. We've got a full day. Okay. Well, good morning. I'm Rich Kinder, Executive Chairman of Kinder Morgan, and I want to welcome you to our 20th Annual Investor Day. Time flies when you're having fun. But before we begin, I'd like to call for just a moment of silence in memory of David Fleischer. David, of course, was a founding partner of Chickasaw. Before that, a long-term player at Goldman Sachs. I think David attended almost every one of these 20 investor days. He died earlier this month, and I'd just like to have a moment of silence in his memory. Thank you. As I said on the investor call last week, the energy industry, in my judgment, needs to do 3 things to ensure its success with the investing public: we need to live within our means financially; educate and convince our investors that there's a long runway for hydrocarbons, particularly natural gas; and address climate change issues by taking all reasonable steps to lower emissions. In other words, be part of the solution, not part of the problem. Now I'm going to address briefly the last 2 of those issues, and Steve and the team will spend the rest of the morning addressing how Kinder Morgan is handling the first of those goals. Hydrocarbons are absolutely required for years to come to meet long-term global demand, and we believe that U.S. infrastructure is the key to that effort. The left side of this slide, based on the most recent IEA study, shows demand growth between now and 2040. And as you can see, natural gas remains on a substantial growth trajectory throughout the period, growing by 36%, exceeded in growth only by renewables. That demand for natural gas, in our judgment, is driven by several factors, with global industrial development being the largest and occurs primarily in the developing economies with about half occurring in the Asia Pacific region. Oil demand increases through 2030, although it slows in the late '20s. Long-distance freight, shipping, aviation and petrochemical demand continue to grow, while passenger car fuel levels off. On the supply side, a large portion of the growth is from U.S. shale. And at the bottom of this slide, you can see some pretty astronomical numbers. The projection is that U.S. shale will play or will supply 85% of the increase in global oil production and 30% of the growth in natural gas production. Again, comes back to my central point that U.S. infrastructure will play a huge role in the future. Slide 6 shows that part of the reason for growing energy demand comes from the worldwide increase in population. By 2030, the projection is that the world will have added 1 billion people, almost all of them, as you can see in this slide, in non-OECD developing economies. Now the fact that the population growth is in the developing world is very important because many censors of those countries, as you can see from this slide, have unfulfilled basics needs and technologies. And as those important needs are satisfied, their use of energy will inexorably climb toward the per capita use in the developed world, which, as you can see on the right-hand of this slide, is about 3x greater than in the developing world. So you've got population and you've got growth in that population in the areas that need energy the most. Now where does the supply come from? The U.S. is expected to produce more energy than it needs, which should lead to a substantial net export position for natural gas, as you see on the right-hand of the slide, as well as oil and liquids that you see on the left slide. Slide 9 shows the growth by economy and by sector. 98% of the growth is projected to be in non-OECD countries like China and India. And the right-hand of the slide shows you how balanced that growth is if you look at it on a sector basis. It's balanced with industrial needs, being the largest, followed by buildings, transportation and agriculture. The fact that industrial needs are so prominent shouldn't really surprise us because so many of the everyday products that are essential to the basic needs of the middle-class existence are based on hydrocarbons. We depend on hydrocarbons as feedstock for everything from detergent, to bandages, to aspirin, to toothpaste, to clothing. You name it, hydrocarbon supports it. And the refining, chemical and petrochemical industries are incredibly efficient in maximizing the usefulness of the natural resources they consume. Now let's turn to the environmental issues. As Slide 11 shows, it's the old Tale of Two Cities. The U.S. and other OECD countries have made substantial progress in reducing emissions over the last decade, while the rest of the world's emissions have increased, especially in India, which is trying desperately to lift hundreds of millions of its citizens out of poverty, which creates a huge demand for energy. This trend is expected to continue over the next decade, as you can see from the center portion of Slide 11. Now let's talk about the U.S. record on GHG emissions, because contrary to what the naysayers say and argue, we've been relatively successful in limiting our emissions over extended periods when our economy, our population and our raw energy use were all growing pretty dramatically. In fact, as this slide demonstrates, some of the numbers are pretty staggering in a positive way. Our emissions are now basically flat compared to 1990 and down 12% since they peaked in 2007. Natural gas is perhaps the largest driver of this reduction as electricity-related emissions are down 28% since 2007, largely because of the replacement of coal-fired generation with natural gas. Now with respect to our industry, as this slide also indicates, I think it's important to know that since 1990, methane emissions are down 16%, while natural gas production is up over 50%. Now that doesn't mean that we, as an industry, don't need to do more, as I said earlier, and Steve will share with you some of the company-specific steps we're taking at Kinder Morgan to address this issue, but there has been a steady decline in U.S. emissions, and natural gas has been the major driver of that. Now natural gas is also a critical partner to renewable energy. As we all know, winds are intermittent and the sun doesn't shine all the time. So other power sources have to ramp up and down to meet demand, and natural gas performs that task very well with lower emissions than other hydrocarbon alternatives. Natural gas is abundant, with significant infrastructure in place. And without a reliable backup, renewals would require excess capacity, resulting in meaningful additional upfront Scope 3 emissions. In fact, it would be interesting to compare GHG emissions from natural gas to renewables when including Scope 3 impacts from wind and solar installations. So I hope you'll take away 4 snippets from what I've said. Number one, developing economies will drive energy demand because of population growth and satisfaction of basic needs. Second, U.S. excess supply will serve that growth. Third, consequently, there's a long runway for hydrocarbon use, especially for natural gas. And finally, U.S. greenhouse gas emissions are declining with the increased use of natural gas playing a significant role in that decline. And I would add that exporting natural gas as LNG to the developing economies I've talked about can help reduce emissions in those countries as well. Thank you, and I'll turn it over to Steve.

All right. Good morning. Okay. So I'm going to pick up where Rich left off. How is it that we participate in this long runway that we see ahead for hydrocarbons, particularly in natural gas? We have constructed over the years and continue to expand on an essential network. It's unparalleled, it's irreplaceable, it's largely must run. If people are using energy in the United States, they're moving parts of it, one way or the other on our system. Decades-long runway and we've got a great position, leading position in multiple commodities, particularly natural gas, which as you see on the right there, is about 61% of our segment. It's also about 67% of our backlog. So heavily weighted to natural gas but also refined products where we have critical key positions at the refining and market centers around the country. And Kim will go through some of the specific assets when she gets to her presentation. But a great network across multiple commodities. We are the leading infrastructure provider in North America. This is also, I think, a core holding in any portfolio, and including in an ESG-sensitive portfolio, and I'll get into more detail on that in a minute. A large-cap company, $40 billion -- greater than $40 billion, actually near $50 billion, one of the 10 largest energy companies in the S&P 500. Also an important point is the level of management and Board ownership in this company. 15% owned by management or Board of Directors. That makes us act and manage and run this company like owners, not like agents. And you can see that in our track record, how we do on our investments, how we allocate the free cash flow that this company generates, highly aligned with the investors in the room. 5% current dividend yield with the increase to $1.25, a 25% dividend growth in 2020. We're really right now close to 6% on a 2020 declared basis. So dividend growth to $1.25 and then a $2 billion share buyback program, we'll return a substantial amount of value to shareholders with the cash that we generate, the dividend increases that we announced and have fulfilled since mid-2017, and also the share buyback program. It's great to have the capacity to have such a program. We've used about $525 million of the $2 billion to date, and we've done it opportunistically. And we've done it opportunistically, which has meant that we've gotten good returns on the investments that we've made there. So also a strong balance sheet, I'll get into that into a second, but large-cap, returning value to shareholders and managed by owners like owners. So a number of milestones that we reached in 2019. As you know, we've sold KML and KMI's ownership position in the Cochin pipeline in the U.S. for $2.5 billion to KMI. We got good value there for our outside shareholders on KML. We're very proud of the work that we've done and the value that we returned to our shareholders on what was really a remarkable experience for that publicly traded company. We've also returned good value, of course, to KMI, and we helped simplify the structure here and also strengthened the balance sheet. Due in part to that transaction, we've created $1.2 billion worth of balance sheet flexibility. Again, a rarity in our sector and the product of work over several years. We've retired $9.4 billion in debt since 2015. We've been working hard to get this balance sheet strength. We're a solid BBB flat, and we now have some capacity on our balance sheet, which we believe delivers value, the option value to our shareholders in and of itself, but it also creates the opportunity for us to find an opportunity to return additional value to shareholders or to invest in attractive projects. We had 2 major projects placed in service. GCX, a little bit early in September of 2019. So 2 Bcf a day, an immediate reduction to flaring. But we had that thing in service and it was a very short period of time, a matter of a few weeks before the basis had blown back out, indicating that we need another pipeline. And of course, we're working on that. Elba, 10 units at Elba, the first unit, which came in, in 2019, that, plus the balance of the plant, et cetera, is 80% -- as well as the part of the project that we own on a 100% basis, delivered 80% of the revenue to Kinder Morgan, just with the first unit going into place. So we have 9 more units. We've got 4 now in service, with the balance of the remaining 6 coming in service over the first half of 2020. We demonstrated capital discipline. One example of that, but it's just one example, is when we didn't see our investments delivering the kind of return we wanted to see, particularly in Tall Cotton in CO2. We reduced the capital program. Jesse and the team reacted quickly. They brought it forward on their own, meaning that this is an organization where our business unit presidents behave like principals as well. But there were also other areas where when we didn't see, for example, gathering and processing developing the way -- in a particular asset, the way it had originally been planned, we pulled the capital out. We pulled about $300 million of capital out of 2019 versus what we had budgeted going in. We've been very disciplined with our capital around here. We've been capital disciplined before it was cool. We've been self-funding our discretionary capital, primarily with operating cash flow. We've been doing that since the first quarter of 2016. As I mentioned, increased the dividend 25% year-over-year for 2019 versus 2018, doing that again for 2020. And we reported, in our second ESG report, reporting our methane emissions intensity. And we're a part of the ONE Future program, which has as its objective, having, from start to finish along the gas production and delivery chain, less than 1% methane emissions across that entire chain by 2025. The storage and transportation allocation of that 1% is 0.31%. We're at 0.02% and 7 years ahead of schedule, beating it hard and 7 years ahead of schedule. Okay. So our strategy comes down to the sector choice and our commercial approach to that sector, how we capitalize our business and how we allocate capital and return value to shareholders. So on the first, the sector, we're in the North American, really the U.S. midstream infrastructure business. The way we contract that business out is largely under fee-based contracts and then largely take-or-pay contracts, where we get paid regardless of the movement in the underlying commodity price. And in many cases, without regard to the level of usage by our customers of the service that we've sold. We're a safe and efficient operator. We operate under multiyear contracts, and I said, largely take-or-pay. On the balance sheet. We're investment grade. We strive hard to maintain a low cost of capital. We have ample liquidity. We're sitting at 4.3x debt-to-EBITDA versus a long-term target of 4.5x, and that's where the balance sheet capacity that I mentioned earlier is coming from. We're very disciplined in our capital allocation. Conservative assumptions are used. We have high return thresholds. We set a 15% starting point and we have discussions about ratcheting down from there where it's warranted. It doesn't cut everything out. If we have a project like a GCX, for example, where we have long-term contracts with good counterparties securing the entire capacity of the facility, et cetera, then we can ratchet down off of that and still be comfortably above and well above our cost of capital. And that's where we aim to be. We think, particularly in this world where getting permits and building out hydrocarbon infrastructure is challenging, we think we're doing well at it, but it is challenging. We think having a good margin of safety on those capital investments is important. So we don't run it right down to the very limit of our cost of capital and just try to chin that bar. We allow ourselves a good margin of safety. We enhance shareholder value through those project investments. Kim will show you our track record there through dividend growth, through share repurchases, and we believe it enhances shareholder value to have a strong balance sheet as well. So I hope what you see in how we're approaching this is we're operating by some pretty tried and true financial principles here. The order of operations is you make sure you have a strong balance sheet. You invest in the NPV positive projects, as I said, though, with the margin of safety. And then you look for ways to return the excess or the surplus cash to shareholders, whether that's in dividends or buybacks. That's the way we're doing it. We're not going with whatever the current fashion of the day or whatever is being talked about as everybody needs to do this, people shouldn't be investing in projects, they should just buy back shares. We do this based on what returns we're going to produce and what value we're going to produce for shareholders. That's how we do it, by the principles. All right. I'll talk about, again, natural gas, 61% of our segment EBITDA and 67% of our project backlog. So a big part of our presence and also a big part of our future. And here, you see our network overlaid over the supply basins that are expected to produce most of the growth between now and 2030. An additional 32 Bcf expected from these 4 areas. And you see Permian leading the way. And certainly borne out by the current dynamics, associated gas -- given dry gas prices, associated or given natural gas prices, associated gas is still economic. 97% of the value of the wells in the Permian are associated with the oil or the natural gas liquids. That makes gas something that has to be moved rather than flared, and it makes it an extremely cheap and competitive alternative to other regions. But still, over the course of this period, still seeing substantial growth in the Northeast and the Haynesville, those dry gas plays. Of course, the Haynesville is nicely positioned for the demand growth that we're going to see on the next slide and also in the Eagle Ford. So overall, natural gas production expected to grow by 30% by 2020. And so the point here, one of the points that Rich made earlier, hydrocarbons have a long way to go. And peak hydrocarbons, and particularly peak natural gas, is a very long way out. I was going to glibly make the comment that we've already passed peak iPhone, but I see their sales were up yesterday. They reported sales up. However, however, peak oil and peak natural gas are a very long way out. And I think if you pay attention to the people who are thinking and writing about this, and particularly, the people who are paid to be right as opposed to the people who are paid to be interesting or who have some sort of other agenda, I think you would agree, we've got a long way to go here. Okay. And then the same picture, same network overlaid over where we're going to see a natural gas demand, while this is still on growth. And the demand centers are laid on there as well. So we have plenty of opportunities as a result of this growth to fill our existing assets and get better values for the services that we have as we fill those assets up, offset some by the recontracting headwinds that we have on a couple of remaining assets. But importantly, as the network fills up, it becomes more valuable. And that's a very capital-efficient way to increase your margin, obviously. It also creates opportunity for us to invest to feed these expansions. We're investing a great deal in Texas right now. The investment we completed with GCX, putting that in service, PHP, the potential for yet a third pipeline there. So it creates the opportunity for us to extract value from the existing network as well as to find good, high-returning capital projects to invest in. So again, our network is extremely well situated, both on the supply and the demand side. And just to lower the microscope a little bit more, a substantial part of the growth in natural gas demand is expected to be in that box or loosely calling it the Gulf Coast, but it's that box. And 84% of the natural gas demand growth that's coming between now and 2030, or projected to come between now and 2030 is in that box. And we have a lot of assets in that box. We have storage assets, we have transmission assets, we have gathering assets, we have connections to the LNG export facilities, Mexico exports. We have significant market shares in both of those markets. And you can see that those are the 2 biggest sources of growth, particularly LNG. And this 15.9 thing to show you on the next page, there's 13.5 Bcf of U.S. natural gas, LNG export capacity that's already up and running or is being constructed right now. So a good line of sight on growth in LNG. This is stated on slightly different terms because it picks up 2019. All right. So here is the U.S. LNG exports. U.S. LNG overall projected to supply 4.5% of the global gas market by 2030. This is now a global commodity. It's no longer a domestic U.S. commodity. It will move in response to global market dynamics. I think where we have an advantage in North America is we have the best, the best midstream infrastructure anywhere on the planet. So we have the storage that will be required, the transmission facilities, the flexibility that those facilities bring, a very robust producing sector, of course. We have some very good advantages in the U.S., in particular, to serve this market. We also aim to be a differentiated provider. So our LNG customers care -- gas is a commodity, but they care about pressure. They care about quality, and they care about reliability and the interface between our operations folks and their operations teams. Those things matter, and so we put good emphasis -- Tom and his team put a lot of -- and Steve will put a lot of their emphasis on making sure we serve those customers well because they are a big part of the growth. And we run between 40% and 45% of the LNG demand in the U.S. We're serving that. So those things matter. We've got, as I said, 13.5 Bcf of capacity that's already operating or commissioning or under construction. So this is a phenomenon that's here, not just a projection. Switching to ESG a little bit. When you look at Asian and European markets, this is showing you how U.S. LNG compares with other sources of LNG, other international sources of LNG as well as domestic coal. So you think about this as, whether it's China or India, domestic coal that has to be transported a short distance and consumed. You look at U.S. LNG, and this includes the production of it, the transportation of it, the liquefaction of it, the shipping of it and the regasification. And we are competitive with LNG from other sources of LNG as well as being significantly better than their domestic coal resources. And you'll see how much we've accomplished in the U.S. Rich talked about how much we've accomplished in the U.S. in reducing greenhouse gas emissions as we've used natural gas in lieu of coal. So replacing coal is critical to the global emissions reductions. The power sector is about 40% of CO2 emission, CO2 equivalent emissions overall. Burning natural gas, 25% more efficient than coal on average. And that's the -- you're directly burning into the turbine. You're not heating up water, turning it into steam, running the steam through a turbine. The steam turbines and gas are recapturing waste heat in a combined cycle unit. We end up with a much more efficient process and converting the BTUs into electrons. In combination, that means 60% less emissions than coal-fired plants. We've brought down greenhouse gas emissions to the early 1990s levels despite, as Rich said, 30% population growth and a 200% increase in GDP and, I would add to that, about a 50% increase in power generation over that period. So we're using more power. We have more people. We have double the size of the economy, and we are back to pre-Kyoto levels, pre-Kyoto levels in the electric sector. There's no reason why we couldn't do something similar or displace additional coal-fired capacity coming on new build coal capacity overseas. Coal-to-gas switching, as IEA has said, provides quick wins for global emissions reductions. So we can do with natural gas elsewhere in the world something like what we've done in the U.S. The other important part here, an important point is we're -- I think in the latter part of last decade is when everybody really, really got serious about climate change and what are we going to do and what's the energy sector, in particular, going to do about it. I hope that we're going to see in the coming part of -- the early part of this decade, is we're going to get more realistic and practical about how you go about solving that problem: what's required; what's the role that natural gas and other hydrocarbons will ultimately play. It's decades to take new technology and fully deploy it in the electric sector. This isn't a matter of typing out new code or optimizing code. This is a matter of replacing installed capital infrastructure that moves stuff, right, that generates massive amounts of energy. That doesn't happen overnight. So we need to get more realistic. Not letting people have gas stoves in Berkeley, for example, is not going to solve this. The U.S. is 15% of global emissions and declining. And what we're doing in the U.S. -- declining in -- as a share but also declining in absolute terms. Natural gas is part of this solution overall. Here's our backlog, $3.6 billion. And as I mentioned, 67% of that is in natural gas with a 5.5x EBITDA multiple. Again, a very disciplined approach to the capital that we're investing. A lot of questions about how we refill that backlog. Kim is going to take you through our historical experience, and you'll see the numbers there. Natural gas is likely to form a significant part of this. And as we look at kind of projects on the horizon that are not on the backlog, we see good opportunities there. But let me emphasize something really important here. We don't feel pressure to refill the backlog. We feel pressure to deploy our investors' capital wisely. We expect we're going to have those opportunities, but we're not going to force it. We'll continue to look for returns that meet our criteria in terms of returning value to our shareholders. We're going to continue to have high return thresholds, and we're going to continue to focus on and be disciplined about and distinguish ourselves in terms of how we develop and build these projects so that we accomplish the returns that we set out to. So the Permian, we have a great situation in Texas. We have a large intrastate natural gas network that feeds the export -- the export markets as well as the industrial pet-chem and power markets along the Texas Gulf Coast. It's a great asset position. It moves about 5 Bcf a day, it's pushing up higher now because we have GCX in service. But we have a 2 Bcf project that came in on GCX, another 2 Bcf coming in with PHP and all of that happening within the state of Texas. And within the state of Texas, there's more commercial flexibility and a better opportunity for us to extract value from the chain. And because we can buy and sell the gas, we do that on a, if you will, hedged basis, we buy and sell with reference to the same index, for example, ship minus and ship plus, Houston Ship Channel minus, Houston Ship Channel Plus. But we do have commercial flexibility to do more with our storage assets, et cetera, in our -- in the regulatory regime in the state of Texas. So the supply and the demand is all in Texas. We've got a great network already there. We're building the pipe that's required to get the gas that's being burned in West Texas, flared in West Texas to a market where it can get on a ship, it can go to Mexico, you can see the pet-chem and the industrial and power markets and get real value for our customers, our producer customers. We also have -- as mentioned here, to debottleneck that network to deal with all the arriving natural gas, we're investing $325 million in that network to debottleneck it to give us more flexibility on where we place those molecules, as they're hitting our system and as they will continue to hit our system. We're supporting the build-out of LNG exports, and I always like to hear about the nature of our participation. So we built the Elba facility. We built that under a long-term contract with Shell, 20-year contract with Shell, where they are paying us a fixed fee for the use of that facility, and they are using their production, their supply sources, their global market -- global markets to place that and make an attractive return on it. But that's a 20-year contract with Shell, and that's a rarity in today's LNG, that's a nonexistent, it's a null set in today's current environment for contracts on LNG. The other part of our business though, and will continue to be a big part of our business, is serving our LNG customers. Serving the LNG builders along the Gulf Coast primarily who need our transportation and need our storage resources so we can participate in that growth in U.S. LNG but participate in it in our way, meaning, we're providing the midstream infrastructure to serve those customers of ours and not taking global commodity price risk. But we've got a great transportation network, we're connected to every major natural gas resource play, great deliverability with our 660 Bcf of storage in place, an important element of the service provision to LNG facilities. So already under contract, the first 2 columns there, 6 Bcf of capacity, 17-year average contract tenure and then another 2 to 4 Bcf that we're working on that will come at some point, depending on the LNG contracting cycle. So a great way for us to participate with our existing network in a significant development in the U.S. natural gas market. Beyond the backlog, a number of things for us to continue to focus on in our natural gas, our CO2 and our refined products businesses in both pipelines internals. And again, we expect that we can find across that network $2 billion to $3 billion of additional growth capital year, but we won't force it, we'll be disciplined about it. Wrapping up with a couple of slides here on ESG again. So we have been working on things that matter from an ESG standpoint for decades, since the early 1990s. And where most of that comes into play for us is on managing methane emissions. It's a powerful greenhouse gas, 25x the potency of CO2. But it's also the thing we get paid to move. We get paid to move it and store it; we don't get paid to lose it. The value of the commodity, even in today's prices, is many times where we get paid to move it. So we've had an economic incentive, a powerful one, for decades, to reduce our methane emissions reductions. This isn't new to us, this isn't something that we started doing 2 years ago when we started doing ESG reporting. This is something we've been doing in combination with EPA, Natural Gas STAR Program, for a very long time. We have also started more in-depth reporting. We've adopted the SASB standard, the 2-degree Centigrade scenario TCFD approach to quantifying our impact. We continue to upgrade our reporting but also our management of the climate change risk and greenhouse gas risk. And that's what this ranking goes to. This isn't a ranking of #2 for the second shiniest report. This is a ranking of #2 for the way we manage this risk. Very important. And so that's put us from a place where I think people would have thought that we, and everybody in the energy business were sort of laggards here, to put us in a leading position. And we're looking for ways in this area too to distinguish ourselves, and I think we have. I think this is going to be more important as utilities are procuring natural gas for the future. Was it responsibly produced and was it responsibly transported? That could matter. We'll see. It's a -- there's only been just anecdotes of that to date. But this could be a distinguishing feature of how we do business. So we're committed to this and the point I'm trying to make is this has been built into our culture kind of all along. We have a very good management system and organizational culture. When we decide to make something a priority, it becomes a priority and people in our operations groups and others make things happen, and we're doing that here too. And we're doing it with an emphasis on not just the E and S, but also the G. We are taking care of our investors' money as we do this. And so here you see our greenhouse gas emissions reductions over time, 110 Bcf of total emissions saved. We're in the top quartile of the midstream sector for our disclosures and our quantitative targets. As I mentioned, we're #2 ranked in terms of how we manage this risk overall. And you can see that we get savings for these projects that we've undertaken in order to reduce methane emissions. And so we're taking care of the ES and the G as well. So just in summary here, we have an essential network, providing services that are going to be needed for decades to come. It can't be replaced by better coding, right? This is something that's going to be around for a very long time. And we are working, as Rich said, to also be part of the solution as people are getting more practical about how do we meet global energy needs, how do we continue to pull hundreds of millions of people around the globe out of poverty, right, while still paying attention to what we're doing from a climate change standpoint. So becoming part of -- being part of the solution as well. All right. Thank you. With that, I'll turn it over to Kim.

All right. Good morning, everybody. We're going to go through a quick review of our business segments, and then a high-level financial review, and then we'll have a break and do a panel after that. So starting with the Natural Gas segment. The -- we've got about 70,000 miles of natural gas pipelines. We move about 40% of the natural gas that's either consumed in the United States or exported from the United States. Over 60% of the earnings before DD&A that we generate, expect to generate for 2020 comes from the Natural Gas segment. And as Steve said, it's just under 70% of our backlog. You can see from the map, and the map that Steve showed, that we touch every major supply area. We touch the Permian, we touch the Eagle Ford, we touch the Haynesville, we touch the DJ, we touch the Marcellus/Utica, and we touch the Bakken, either with our transmission lines or through our gathering lines. And on the demand side, as Steve pointed out, 84% of the growth is expected to occur in and around the Gulf Coast, where we've got significant asset position. So beyond the $2.4 billion backlog, we do see opportunity for continued growth in this segment. And so on Slide 34, first of all, exports. As Steve showed you, 2/3 of the growth in natural gas demand between now and 2030 is expected to come from exports, 15.9 Bcf from LNG exports and 2.7 Bcf from exports to Mexico. So currently, we move about 55% of the exports to Mexico, and we move anywhere between 40% and 50% of the -- of supply going to LNG export facilities. So we're in a strong position to compete for the incremental growing volumes. Shale-driven expansions and extensions. As Steve showed you, there's 4 basins where we expect 32 Bcf a day of growth. On the supply side, we've got gathering systems in the Haynesville and in the Eagle Ford, also a very substantial premier position in the Bakken. And then our transmission pipes touch the Permian and the Marcellus/Utica. Storage and line pack support for increasing variable demand. Historically, the variability in natural gas demand has been seasonal. So you saw peaks in the summer and you saw peaks in the winter. Well, with the addition of renewables to the power generation stack, where when the wind doesn't blow or the sun doesn't shine, natural gas has to ramp up, and with the variability that comes in LNG demand when there's a weather event, when there's maintenance, when there's different conditions in the world market, natural gas has to ramp up very quickly or ramp down very quickly, and that's creating more variability. What that means is 650 Bcf a day or Bcf of storage becomes more valuable. Also, our ability to use line pack to deliver customers gas to meet those ramp-ups or put gas into line pack when we ramp down, those services become much more valuable as the load becomes more bearable. Gulf Coast petrochemical and industrial demand, given where this demand is going to occur, in highly congested areas in and around the Gulf Coast, this is going to be a place where incumbents will compete very, very well. Pipeline conversions and I would also say reversals. As it has become harder to build new pipelines, pipe in the ground just becomes more and more valuable. So we have been very successful over time identifying places to convert underutilized pipe or reverse underutilized pipes. KMCC in the Eagle Ford, we converted from a natural gas pipe to a crude and condensate pipe. Hill Country, which is in and around Austin, we converted from crude to natural gas. TGP, Tennessee Gas Transmission, we reversed coming -- it's to come back south out of the Marcellus and Utica. Cochin we reversed and did a slightly different product. And we've looked at a whole bunch of others that I could name over the years. So we've got a team that's constantly looking for our underutilized assets and looking at ways to utilize those. Operating leverage. The Natural Gas Pipeline business is a classic fixed-cost business. You've got high fixed cost, low variable cost. And so when we get more volumes on our systems, when we can deliver valuable services and charge more for those, that drops to the bottom line. So there's a lot of operating leverage in this fixed-cost business. And then end user and LDC demand growth. We have -- we are in a unique position so that we'll have last-mile connectivity to a number of LDCs. If you look at our SNG system, we've got over 350 interconnects with LDCs. That's multiples of our nearest competitor. If you look at NGPL, it's got 78 interconnects with Nicor, and we have more with Peoples Gas. And so as that demand grows, we're in a good position to meet it. So those are some of the industry trends that we expect to capitalize on to add to the backlog in Natural Gas. Now moving to the Products segment. Products is about 16% of our overall business. We've got about 9,500 miles of pipe, which -- through which we transport petroleum products, that's gasoline, diesel, jet fuel; or crude and condensate. We've also got about 55 million barrels of tankage in the segment, which is largely located around our pipes. And going to the next slide, if you look at how the 2.4 million barrels a day that we move through this 9,500 miles of pipe breaks down, about 75% of the volume is petroleum products. That's gasoline, diesel, jet fuel. About 25% is crude and condensate. On the clean product side, we get paid a fixed tariff, okay? And that's a fixed fee business. That tariff escalates every year. Right now, it escalates at PPI fixed goods plus 1.23%. That adder, the 1.23% is reviewed and reset every 5 years by FERC. This year, we expect that in place and adder to be about 1.9%. The Products pipeline is also a high fixed cost, low variable cost business. And so if you just take a simple example and say, you make $100 in revenue in year 1. And in year 2, you get an inflation adjuster of 1.9%, then you're going to make $101.9 in year 2. If your operating costs, you can hold them flat, and so $50 each year, then the first year, you're going to drop $50 to the bottom line. And the second, you're going to drop $51.90 to the bottom line. And so that 1.9% on the top line turns into about 3.8% on the bottom line, okay? And that is just the tariff escalator. That doesn't include any potential volume growth. And so I think people sometimes forget how valuable that tariff escalator is. On the volume side, if you look, EIA is projecting growth in gasoline, it's projecting growth in diesel and jet fuel for 2020. If you apply those percentages to our mix of products, then you would -- we would expect our volumes to grow by about 0.5% in 2020. Generally, we do a little bit better on our pipes than the national average. On the 25% of the business that's crude and condensate, that's a premier gathering system in the Bakken. And that's our KMCC pipe, primarily in the Eagle Ford, which could take volumes either from the Eagle Ford or from the Permian. So despite rumors of the demise of petroleum product demand, if you look at the third chart from the left, we continue to see steady increases in U.S. demand for transportation fuels. And so why is that happening? We think there are a couple of reasons that that's happening. First, if you look at the chart on the left, our EV market share. If you look at the top 12 car producers in the United States, they produce, I think, about 54 million cars per year. And the EV penetration in 2018 was 1.3%. So it's -- has been much lower, I think, than people were projecting. The other thing is a preference for larger cars. If you look at the SUV market share, it continues to go up in the U.S. and it's going up across the world. And then the last chart on the right, global air travel continues to increase. So we continue to see some nice, steady increases in petroleum product demand and expect that to continue. Turning to the Terminals segment. Terminals segment is about 13% of our overall business. We have 2 primary types of terminals. Our liquids terminals where we store gasoline, diesel, jet fuel, chemicals, that's about 75% of that business on a revenue basis. We've got 79 million barrels of storage. And generally, those are backed by take-or-pay contracts from our customers. The other 25% of the business is bulk terminals. Bulk terminals, here, we're storing and transloading products such as petroleum, coke, coal, copper and ores. And here, we generally get paid on a volumetric basis, so it's a fixed fee from our customers, and then we get paid based on the volumes that we move. Over 50% of our liquids terminals is located in the Houston Ship Channel, on the next slide. We've got about 43 million barrels of total capacity in the Houston Ship Channel. We have unmatched scale and flexibility. We've got 29 inbound pipes, we've got 18 outbound pipes, 16 cross-channel lines, 11 ship docks, 38 barge spots, 35 truck bays and 3 unit trains, okay. We're connected to 10 refineries in and around Houston, and we're connected to facilities -- 10 other facilities that provide products that we can blend like naphtha and butane. So when customers come to us, we can blend almost anything they want to blend. If they want to go out on a ship, we can take them out on a ship. If they want to go on the intercoastal waterways, we can take them out on a barge. If they want to go on a unit train to Mexico, we can move them there. If they want to go on an outbound pipeline, it's the East Coast, if they want to go to the Midwest, we can take them on Colonial or Explorer. And so if they want to go into the local market, we can move it through a truck bay. That is very valuable to our customers. And so we have seen some competition come into the Houston market. We've seen some new build there, yet we've largely been able to retain our customers because of the scale and flexibility that we have in this facility. In fact, in the fourth quarter of this year, we moved 137 million barrels through this facility. That's 1.5 million barrels a day that we're moving through this facility in the fourth quarter of last year. And we're investing a little bit over $170 million to make some additional improvements here at nice returns. In addition to the record throughput that we saw, we've continued to see increases in volumes going over our docks in Houston. Now U.S. exports have grown as well. If you look at U.S. exports overall, they've grown by 7% per year since 2016, we've grown at 12% per year. And that's a function of our position on the Gulf Coast, okay? The U.S. Gulf Coast refining capacity is some of the most efficient refining capacity in the world. And it has been expanding slowly through refinery creek, through some expansions in order to meet worldwide demand, okay? And so those barrels are being exported. And so this is a trend that we would expect to continue over time. Finally, turning to the last segment. Our CO2 segment is 10% of our overall business. About -- this breaks down into 2 component pieces. About 40% is our sales and transport business. This is where we're moving CO2 from Southwest Colorado down into the Permian Basin and selling that CO2 to customers. This is -- this business is underpinned by long-term take-or-pay contracts, which have average of 9 years remaining on them. So a long term, very stable business. About 60% of this business, so about 6% of KMI overall, is our enhanced oil recovery business, where we inject our CO2 into our own oilfields and produce oil. This business is a little bit more risky than our other businesses, 6% of our business, so relatively small. But because of that, we target and require much higher returns in order to invest in this business. And then the way that we manage some of the risk on the price side, for the near and the medium term, we aggressively hedge the oil exposure. On the volume side, we have been very good in the short term at calling our shots. We've been within 2% of our budgeted volumes in CO2 over the last 10 years. And so we're able to call our shots in the short term. Over the long term, the concern is that this is a depleting resource and that volumes will decline. Well, if you go back and look at investor conferences, for the last decade, we have been able to move -- push out that projected decline as we find different ways to get at the significant original oil in place but still remaining primarily in SACROC and Yates. And we have the potential to add more at SACROC that we're looking and have accessed some of the transition zone, which has the potential to add 700 million barrels of original oil in place to SACROC. So how have we done on our CO2 investments? And so I'm going to start with the chart on the right, where you can see the significant cash flow that the CO2 business generates. In the maroon is the free cash flow. And so you can see, on average, for the last 11 years, we've generated $550 million per year of free cash flow in that business. You can also see in 2015 through 2020, the free cash flow is lower as a result of lower oil prices. But even during that time, we generated over $460 million of free cash flow in this business, okay? If you look on the left side, you can see our returns over a very long period of time. So 2000 is essentially the inception of this business. And through 2019, on our oil and gas business, we've earned an 18% unlevered after-tax IRR. If you looked at our CO2 -- at the total CO2 segment, it's 28%. So we've been able to achieve nice returns for our investors in this segment. Now turning to the financial review. On this slide, what we show you is the cash flow that we've generated, the significant cash flow that we've generated from cash flow from operations and asset sales, and then how we've used that cash flow. Now generally, what we use as management when we're looking at this is distributable cash flow as opposed to CFFO. The reason we typically -- we like the distributable cash flow better is it's not impacted by short-term moves in working capital. Also, because when you sell assets, when you have to pay taxes on those sales, that hits cash flow from operations. It's not netted out of the asset sale in the investing section, so it hits CFFO. And then per GAAP, a significant portion of the distributions that we get from equity investments hit cash flow from investing, not cash flow from operations. But I know that some of you like to see CFFO. And so that's what we've shown here. So if you look, CFFO in every period significantly covers the dividend. And in every period, we're covering the dividends plus the CapEx. So we are funding our dividends and our CapEx with internally generated cash flow. And then if you look at the asset sales, generally, what we've done with that is used it to pay down debt. And as a result, primarily the asset sales, we have reduced debt by $9.4 billion since the third quarter of 2015. On the next page, we look at 2020, because the prior page was through 2019. So our 2020 budget, we expect to generate $5.1 billion in DCF. We'll pay 2-point -- we have $2.4 billion in discretionary CapEx and $2.7 billion in expected dividends at $1.25. So again, cash from -- flows from the assets are covering our dividends plus CapEx. And then we've got $1.2 billion of balance sheet flexibility that was created largely as a result of the Cochin and KML sale that we can use for share buybacks, we can use for incremental capital projects that we might identify during the year, or we can retain on the balance sheet for opportunities that we identify in future years. Now our assets generate very stable cash flow from high-quality customers. If you look, over 90% of our cash flow comes from take-or-pay or fee-based contracts. 64% of our cash flow comes from take-or-pay contracts. What that means is that we're entitled to payment regardless of throughput. So price is fixed and volume is fixed. 27% of our cash flow is fee-based. What that means is we have no price risk. The price is fixed, but the volume is not fixed. And generally, we get paid on a volumetric basis, where we have these fee-based contracts. And so 2 primary cases or businesses where we have this arrangement with our customers. One is in the petroleum Products segment. The petroleum product demand is very stable, and as I have showed you, has been growing, and we expect to continue to grow slowly over time. And so the volume in this business is very stable. The second place where we have these fee-based contracts is on our gathering business. We get paid a fee, and then we get paid based on the amount of volumes that we move. But we have very nice positions in economic basins. 5% of our cash flow is hedged. This is primarily in our CO2 segment. And we're hedging primarily crude oil. Here, the -- so we're hedging the price, the volumes aren't fixed. But as I mentioned a minute ago, we've been very close to budget over the last 10 years. And then 4% is unhedged, and this is primarily the crude oil exposure in our CO2, where our sensitivity for 2020 is $5, plus or minus $5 in DCF for every dollar change in a barrel of crude. Now so our contractual nature in our business relationship with our customers is very strong, but who are our customers? We have very high-quality customers. If you look at our customers that are greater than $5 million of expected 2020 revenue, that's about 86% of the total. Then 78% of those customers are investment-grade, or we have substantial credit support. There's only 3% that are B- or below. And 71% of the revenue comes from end users. And the importance about it coming from end users is generally, no matter -- is because it's generally a needed service. So no matter what happens to the counterparty, whoever steps in, will generally need that service. Now we spend a lot of time on credit. Every single week, we go through any outstanding receivables that we have with a noninvestment-grade credit. We also go through any change to submit the rating on any significant customer, so that any given point in time, we know if our customers are being upgraded or downgraded. And then on a monthly basis, we go through every outstanding receivable in the company and to determine who's not paying, when are they going to pay, what's the story, do we need to send a demand letter, do we need to call on any collateral that we have, so that we're getting in front of any issues. Now if we look at how our cash flow breaks down across the segments, 97% of the Natural Gas segment is either take-or-pay or fee-based. And actually, 80% of it is take-or-pay. If you look at the Terminals segment, 98% is take-or-pay or fee-based, with 70% of that being take-or-pay. Products segment, 93% take-or-pay or fee-based. We talked about the fee-based, the 72%, being backed by stable petroleum product demand. And then our CO2 segment, 84% is hedged, take-or-pay or fee-based. I think something people forget about CO2 is 29% of the CO2 segment has take-or-pay contracts. This is on our sales and transport business. So looking at our discretionary CapEx spending levels. We said today, and we've said on numerous occasions before today, that we expect that we can invest $2 billion to $3 billion per year in discretionary capital. And one of the reasons that we have confidence in this is looking back at history over the last 11 years through different types of commodity pricing cycles. And on average, we've spent about $2.7 billion per year during this time. Now Steve made this point, I want to reiterate this point. This is -- $2 billion to $3 billion is what we think we can achieve based on looking at the opportunity set in front of us and based on what we've done historically. But this is not a target for us. We are not going to drop our return thresholds to get -- to bring $2 billion to $3 billion in the door. If they're not $2 billion to $3 billion of opportunities that hit our return thresholds, then we can use the money to repurchase shares. We can take that money and apply it to the balance sheet and just wait for a better day, okay? Because -- now what that means is if we apply it to the balance sheet and wait for a better day, that our growth might be a little bit more lumpy and not as consistent. But ultimately, that is going to bring more value to our shareholders than dropping our return thresholds. So again, I want to stress that this is what we think we can do, but we're not going to force it. On the next slide, I want to look at the returns that we have achieved on the capital that we've invested, given the amount of capital that we've invested in the past and expect to invest in the future. I showed you how we've done on our CO2 investments when I went through that segment. This shows you the build multiples, and that's just the capital invested over the year 2 EBITDA for the other segments, for Terminals, Products and Natural Gas, for projects that we have completed between 2015 and 2019. So if you look at the $12.3 billion, and this is based on when the projects were completed, we've completed, during that time frame, $12.3 billion in projects. When we went to the Board, we told them that we -- to get approval for the projects before we started them, we told them we expected to achieve a 6.1x multiple. What we actually achieved was 5.9x. So we did slightly better than what we expected. If you look at Natural Gas, given the significant portion of the backlog that it is, we've invested $7.6 billion. What we sought permission for the Board and got permission was to do a 6x project. And what we've actually achieved is 5.5x. So the bottom line is that we've done slightly better on our projects than we anticipated. So the question people ask is, okay, well, if your project returns have been that good, then tell me why your EBITDA has not grown more than what we've seen. So if you look at our EBITDA, on Slide 49, in 2014, we had about $7.4 billion of EBITDA. In 2020, we're expecting about $7.6 billion. So here is the bridge to get you from the $7.4 billion to the $7.6 billion. The $30 decline in crude prices between 2014 and 2017, that reduced EBITDA by about $600 million. Another -- it's been reduced by another $600 million as a result of asset sales. Now as I showed you earlier on the sources and uses, that -- those asset sales, we largely took those proceeds, applied to the balance sheet, and that's largely what drove the $9.4 billion net debt reduction. There's also been a $300 million reduction in the price and the volume in our midstream segment. And then there's some odds and ins in other categories that net out to $100 million. And then the projects that we've -- that have brought in revenue from -- after 2014 have added $1.8 billion of EBITDA, okay? So the point is, despite tremendous change in commodity prices and significant asset sales that have improved our balance sheet and given us flexibility, we have maintained and actually slightly grown our EBITDA. So in summary, we think KMI represents a compelling investment opportunity. We've got 90 -- greater than 90% take-or-pay or fee-based earnings. We've got tremendous size and scale, $7.6 billion in 2020 budgeted adjusted EBITDA. We've got a 5% dividend yield approximately, based on what we declared in January for the fourth quarter of '19. We expect that we'll increase that dividend 25% to $1.25, and so that yield is going to increase based on today's stock price to just under 6%. So a very attractive yield. We've got a highly aligned management team that has a 15% stake in the company. We've got balance sheet flexibility, and we've got an active stock buyback program. And so with that, I think we'll take a 15-minute break?

Yes, so we're going to take a 15-minute break; if everyone would be back by 9:25. And so what we're going to do is, next is a panel with the business unit presidents with an opportunity to ask questions to them. There is an app we're going to use to get the questions served up. I'll kick things off. But the app is Slido. There's a card next to you on the table there that tells you how to log into -- how to use it. And the password you're using, or rather, the event ID is K-M-I-D. And then there's also the Wi-Fi network password that we'll use, is on there as well. Okay? So we'll be back at 9:25. Thank you. [Break]

If you all could take your seats, we'd like to get started with the next part of the presentation. Okay. As I said just before the break, this is how you can get logged on to be able to post a question. And I think there's even a voting mechanism in there so we can help us prioritize the questions a bit. I'm going to kick the panel off with a question for each of our business unit presidents. So I have Tom Martin here, President of the Natural Gas Pipeline Group; John Schlosser, President of the Terminals Group; Jesse Arenivas, President of the CO2 Group; and James Holland, President of the Products Pipeline Group. So I'll start it off, and then we're going to take questions and post them up here on the screen. And again, it's a little bit different format for us this year, but we thought it would be useful for you all to have an opportunity to ask questions directly to the business unit presidents. They and their teams are really on the front lines of the developments and the deals, et cetera, that Kim and I and Rich were talking about as we went through our presentations. So I'm going to start it off, and, James, I'm going to start off with you. So what are your expectations around the potential impact from the FERC index adjustment to be established later in 2020?

Well, when you look at it, the Producer Price Index for finished goods has been going up, has been going up for the last couple of years. And when operators file their Form 6s later on this year, about in April, I think we'll see price increases on operating costs. The wildcard is really what FERC decides to do as a result of the 2017 tax step. But aside from that wildcard, I think the index will be positive going forward. And we'll work out the details after we hear later from FERC.

Okay. And as Kim pointed out, that's a nice uplift that we naturally get along with a small amount of refined products growth that we see in the U.S. The index helps get a little uplift and, of course, without acquiring additional capital. Okay. Well, I'm going to move on down the line. Jesse, CO2 oil production decline. You have been -- you and your team have been able to maintain oil volumes for a remarkably long period of time, but the volume did trend downward in 2019, I think about 5% when we were looking at it in the fourth quarter, year-over-year, quarter-to-quarter. What do you expect the trajectory of production to be going forward?

Thanks for the question, Steve. Yes, I think we -- if you look at our asset base, we operate world-class assets, both on the source side and in the Permian Basin on the EOR side. So we have billions of barrels of oil in place. The SACROC estimate is about 3 billion barrels. Yates is about 5 billion. So we've got very large targets. We continuously seek ways to prolong the life of the assets. We've got a lot of exciting news in the recent past with regards to the transition zone. So we are implementing that at SACROC now. That's also present at Yates. So we anticipate that we will continue to be successful in prolonging the declines out in time. We benefit from vertical integration, so we can timely adjust to different commodity pricing environments, whether we choose to delay or accelerate investments in those assets. So again, I think when you think about the asset base, it's just a very substantial resource. We've got the best in the industry from a technological perspective, and we continue to find ways to push that decline out.

So a lot of original oil in place still to exploit. We've got what we need to get it out, which is we have CO2, and we have an EOR team that's good at finding those opportunities. So why don't you go on to talk about your views on Goldsmith, Katz and Tall Cotton and how you're managing those opportunities going forward.

Yes, consistent with our capital discipline, we've been -- Tall Cotton is probably the largest upside project we had in the conference last year. And what we're seeing there is we're seeing slower processing rates, which you know that pushes the oil response time out. In the current pricing environment, that strains the economics. So while we're still going to continue to understand and develop processes to see if we can accelerate that processing rate, we did pull back the capital in '19. We're not planning on expansion projects in '20, but we do have some analytical work to do. So I think there's still some upside, a different pricing environment there, if we can't resolve the processing rates. Goals within Katz, again, I think there are opportunities at a higher commodity price environment. But for now, we expect those will modestly decline for the next couple of years until we either find some alternate methods or we get some pricing help there.

Okay. John, how do you expect to continue to deliver growth on your Houston Ship Channel assets in the face of flat to declining domestic demand for key products, including gasoline, diesel and heavy oils?

Well, the short answer is additional exports and continued market share growth. But if you refer back to, I think, it was Slide 97 there, where Kim walked us through what we've been able to build there, it doesn't tell the whole story. If you look back when Kinder bought these assets in 2001, we had 17 million barrels of storage. We had 2 ship docks and 3 barge docks. We handled less than 100 million barrels of storage. Fast forward until now, we're up to 11 ship docks and we'll handle over 500 million barrels. We crossed that mythical level this past year, 500 million barrels of throughput through this unrivaled set of assets we have there. So kind of the longer answer is if you want optionality, you want modal choices, you want to blend, you want to trade, you want to be in this hub, you absolutely want to be in this hub. The other answer would be that the docks we built, the 11 docks we built are underutilized right now. 17% additional upside capacity, a budget, 25% additional upside capacity the last year without having to put another dollar into any of them. We could also pipe up another bulk dock so we could add 1 additional dock. And we have 2 additional docks at BOSTCO fully permitted that we could build there, plus a pipeline by the way. We've been paying on that could connect that and our Pasadena and Galena Park assets. So we feel that we will continue to see very, very strong growth. And if you look at our track record, gasoline and distillates on the Houston Ship Channel has grown 8.6% every year for the past 5 years, and on the distillates side, it was 3.6%. And as Kim mentioned, our exports have grown over 12% a year for each of the last 5 years. So we've proven time and time again that this is the place to be if you want to move a barrel of gasoline and distillates.

So yes, as John has said for many years, this is not a contango tank play. This is not a one-way move, bring it in and take it off offshore. There's just multiple, multiple options when you get into the hub facility and the Houston Ship Channel. All right. Moving to Natural Gas, Tom, please provide your view on global LNG growth and the incremental opportunities for us that you see there.

So we have 6 Bcf a day of long-term commitments to LNG export facilities primarily along the Texas-Louisiana Gulf Coast. We're about 3.5 Bcf a day into that, actually flowing now, so another 2.5 Bcf a day between now and, call it, early '23, early to mid-'23. So that's all done. That's under contract. $1 billion worth of capital deployed there, nice returns. And we will see ancillary services, storage opportunities, balancing services sort of evolve off of that initial 6 Bcf a day. And then on top of that, we've got over 4 Bcf a day of incremental opportunities with the second wave that we are at various stages of development not in the backlog yet, some maybe soon, but -- so very excited about the opportunities on those projects, potential projects as well. And I think longer term, just as the overall need for gas around the world increases, as we talked about earlier, that market, the LNG market will be more commoditized, more of a traded market. So we will -- with the network that we have in the United States, particularly at Kinder Morgan, flowing 40% of the gas across the country and export, the liquidity around that market as it evolves from a domestic market to an international market, we will see additional ancillary services to come over the coming years that really are not part of a capital project. They're just part of what we do in the domestic market today. We think there'll be additional value created from that platform as we go forward.

Okay. So we're going to turn to the questions that are now posted on the screen here, and I'll start with Tom. How would you characterize, Tom, the dialogue with the Railroad Commission, if any, on flaring? And do you expect to see any regulatory changes there.

Yes. I mean, we're not aware of any specific conversations there with the Railroad Commission, and I think there's clearly a desire to get flaring down over time. And I think even the major producers feel a level of responsibility to get flaring down over time. And so I think that's part of our efforts to help bring infrastructure to bear so that we can get those volume -- the flare volumes down. I think that's ultimately the entire market really wants to see that happen. The oil is clearly -- we have plenty of capacity to move the oil right now. So the issue is just getting gas capacity online.

Yes. So there's certainly an economic dimension to that, the regulatory dimension. But also, what we've heard from our major customers there is there is an ESG-related focus, too, on making sure that they meet their internal targets for flaring reduction as well. So building out the infrastructure to help them do that is, obviously, what we're trying to do. And on our PHP Project, which there is a little controversy around, happy to report that -- well, Tom, I'll let you report on our recent progress on right-of-way.

Yes. So we're -- I think we announced on the call last week, we were over 99%. Now we're 100% acquired in all right-of-way, and we have all of our permits but for the Army Corps permit, which we expect that to come in the very near future.

And now we also have in all of the Hill Country counties, we have voted approval on like our road use permits and our required county permits as well, so very important couple of milestones for us there. But where I was going with the comment is, I think while we've had some opposition on the ground in the Hill Country, we've continued to engage with everyone. We've worked through issues with our landowners, et cetera. But it's starting -- it's apparent in this debate, increasingly, that we need to reduce flaring in West Texas. No matter where you stand on these various issues, that's a good thing. It's a good thing from an environmental standpoint. It's a good thing economically. And we're going to unlock a lot of value out there for producer. Our producer customers can unlock a lot of value out there. Billions of dollars which will be going to royalty owners, it will be going into new investments in local communities. And it's also a pretty important part of the budget bill that got passed in last year's Texas legislative session, where additional school funding and preschool funding is getting paid from the -- paid for with the benefits that we're expecting to realize out of the Permian. So again, there's a lot of -- there are a lot of dimensions to it, but getting our pipeline in place is very important. Okay. Several states like New Jersey -- what do I do with that? Let's start over. What are the headwinds to commercializing Permian Pass? And what's the latest on the project timing? Will [ LIBOR ] tests in 2020 change in key perspectives?

Yes, I think the balance sheet discipline that many of the producers are under have caused some slowdown in commercial progress overall with Permian Pass. But ultimately, there is a commercial need. We believe that to be the case sometime in 2023. And so if you back up from there, whether it's Permian Pass or another project, we think something needs to be commercialized sometime this year for that time line to make sense. And so we believe, looking at any analysis, whether it's ours or WoodMac or other parties, there's at least 2 additional pipelines that are going to be needed after ours and Whistler goes in. So we think Permian Pass is as good as an opportunity as any to be one of those at least 2 additional solutions. So I think as we progress through 2020, we'll have a better read on exactly the timing of execution on that project and ultimately, the level of commercialization.

Okay. All right. John, with the fall in coal volumes the last few years, are you repurposing the coal-handling facilities? Or what is happening with that capacity?

Well, we're budgeting -- well, we did around 10 million tons last year. We're budgeting slightly over that for the coming year. The demand is still there on the met side. You need met coal to build steel, and that demand is not going away. So we'll continue to handle it. But we're always looking at the best and highest use for any of our assets, and each of these assets have great bones in them. So they have incredible rail infrastructure and very good jetties. A good example of that would be a Pier IX facility, where there's 3 very, very deepwater docks and an uptake that you can handle 2 unit trains through it. So we're constantly looking at are there other projects potentially we could look at any of these facilities to repurpose. We've looked down at our IMT facility in the Lower River co-locating petrochemical companies at the site. You've seen a couple of them potentially announce over the last couple of years. We'll continue to look at that. But that's true of any of our facilities. If we could find assets that make more sense at that site, we will look at conversions. A great example of that would be our deepwater facility. It started as a petcoke facility. We added coal to it, we added ethanol, we added a crude unit train facility, and we're potentially looking at clean products over the dock now. So the facilities are very, very strong from an infrastructural standpoint and allow us to be flexible as far as what we potentially could do with them down the road.

So John, if you can also kind of quantify or put into perspective, what share of your business is associated with the...

It's a very small portion of our business now. It's less than 5% of our earnings comes from coal business now. And a majority of that is at our Pier IX facility under long-term agreements with mostly met now, but we do handle some steam as well through the facility.

Okay. All right. Several states like New Jersey, Oregon and New York have announced major energy efficiency efforts. So how do you see this impacting your gathering and long-haul assets? Tom?

So I think, overall, there's still a tremendous need for last-mile connectivity into these markets, and we have the footprint to do that. And so the rate of growth of their demand may be impacted by these efficiency targets, but there's -- it's increasingly clear that it's going to be extremely difficult, if not impossible, in many of these venues to get incremental infrastructure built into these areas as well. And so yes, there may be some efficiencies impacting the rate of growth of demand in the areas, but we do believe last-mile connectivity, current last-mile connectivity and expansions off of that last-mile connectivity ultimately increases the value of our network over the long term. That kind of really speaks to the actual gas use. But then the -- on the renewable side, and this is more of a West Coast initial discussion, although the trend is moving east, the -- we're seeing an opportunity and a need from our customers to change the character of our transportation services to be more deliverability-related and pressure-related than steady-state 24-hour ratable services. And so we see that as the kind of current and next wave of opportunities to go across the country to repackage our capacity and serve those market needs, backfilling renewable intermittency.

Yes. So you might talk about that just a little bit more; the difference between demand, supply-demand for the commodity and demand for deliverability, as illustrated on one of the slides in Rich's presentation.

Yes, there was a really good slide that showed, over the course of a several-day period, the range of variability of energy being put out by solar and wind and the falloff of that and how dramatic of an impact gas had to step in and fill that void. And we've seen that -- actually, currently, we've seen that in 2019 in several different venues, again, mostly out west initially, kind of leading indicators and either in the Rocky Mountains or out in California, where there have been huge swings of volumes and pulldowns of pressure because of the variability of renewable. And so again, I think, over time, there's actually a scenario where if we continue to push through more and more reliance on renewables, there may be a need for additional gas pipeline capacity to carry that 24-hour variability that we see to provide the pressure that's required to fill that gap for a renewable.

Yes, a very important distinction between the demand for what we do, just having the facilities there and available for people to meet their peak demands, the deliverability versus what the usage of the underlying commodity is. But going to the usage of the underlying commodity, residential and commercial has been incrementally adding efficiency over time. Those of you who cover utilities, I'm sure you see this phenomenon of additional hookups don't necessarily translate into actual demand growth for the commodity efficiency, is taking a little flip out of the demand every year. But we take that into account when we do our projections. When third parties do their projections, they take that into account as well. And Tom, when we talk about the demand outlook here, it's really not driven by [ RMC ]. It's driven by the...

Yes. Yes, exactly.

LNG exports, exports to Mexico and power demand. So okay, next question. Any opportunity on the Bakken gas takeaway given the residue gas constraints that are supposed to be hit there?

Yes. I mean, we -- I think we've been talking about that for the last few quarters as there being a need for a residue takeaway solution. We are still working on that with others as well but nothing that we can bring to bear today to talk in great detail. Clearly, there's a need. We have infrastructure in the area that is somewhat -- or at least near the area that's partially underutilized. And so we're looking at opportunities to partner with others in the area to bring a solution there. So stay tuned.

Okay. Where do you see the most significant opportunities in your business to repurpose land or assets, either yourselves or in a sale to a third party? John, I'll start with you on that.

Sure. I'll take a step back on that though. If you look at what we were able to do in Canada, every one of those liquid facilities was on land that we didn't own. We borrowed it from somebody. We did a JV. We used Trans Mountain assets or leases. So the example that we are employing at many of the other facilities, whether it be a place like Pinney Dock up in Ashtabula, where we're long on land, down in our Seven Oaks facility in Louisiana, our St. Gabriel facility in Louisiana, we're long at land at many of our facilities. We're constantly on the lookout for customers that we could attract to the facility and then utilize existing tankage, dockage, et cetera, to provide services to them. And I think there'll be many of those opportunities over the coming years.

How can we get more natural gas to Boston and other cities in New England?

That's a good one.

I mean, at least the people in the room who are interested in the answer to that.

Yes. No, I mean, I think really the best solution for us to participate in that is just kind of extensions and expansions of our initial or our existing network up there. It's small, compression-type expansions and even those are not easy to get done, but we believe we can get them done. And so those -- instead of a mega project like NED, I think it's really going to be more small-scale expansions that help serve that market on an incremental basis.

And we have some of those underway.

We do.

And we continue to be working with our customers to try to meet their needs in the best way we can. This -- I'll make another broader point here, though, too. I mean, obviously, we had a project and we were advancing a project that would have added significant capacity, a $3 billion expansion off of our Tennessee system that would have added significant capacity into New England. We pursued that, and I just want to point out just how we manage things and how we make decisions on what that illustrates. We backed away from that project because we couldn't support the economics of it. We took that decision fairly early when you compare it to other projects. And that is a sign of the way we run things. We're not just going to bull ahead because it ought to get done and because we've got pride in the project that's developed. We're going to make the right decision for our investors. We're going to assess the reality. We're going to do it in a very cold and rational way to make sure that we're doing the right things with your money. And so I think when you talk about capital discipline, when you talk about managements with agency risk or not agency risk, it's good to look at the things that we didn't do as well, and that's one of those. Painful decision at the time, but the right decision. And we're finding and we're working with -- we took up immediately talking to our customers about what can we do for you now and produced a couple of projects out of those discussions. We didn't participate in a big interior build in Mexico. We could not get comfortable with the returns and with the terms of the tender. We didn't participate in build-out crude pipe, we tried. We got a lot of crude pipelines from the Permian. We couldn't make the numbers work. And other people had different economics, different upstream and downstream considerations, but it's not a -- but our circumstances for our investors, we couldn't make it work, and so we didn't, right? We didn't participate in it. Our experience in Canada. I think we sold that asset to the one entity that can get that pipeline project built, but we made the right decision for KML and for all of our investors in KML in the way we handled that. So sometimes, the things that you do the best are the things that you don't -- the best decisions are the things you decided not to proceed with and -- but we would love to be able to help provide additional -- we've got a great asset position up there. We'd love to be able to provide it, but the environment has to be such that we can get it done and get it done in a way that's going to produce good returns for our investors. John, what is your outlook for the Jones Act vessels?

Well, [ Scott Grantham ] was here who runs it for us. He'd be disappointed if I didn't flag that. We have 16 Jones Act vessels. They are the youngest, most fuel-efficient fleet in the business. The market has gotten very tight over the last number of years and will continue to get tight, we believe, into the future. We've seen prices slowly creep up. We have 3 vessels, only 3 vessels that are coming up for renewal this year and we expect to renew those at very strong rates. So overall, demand seems to be strong and growing, mostly across the Gulf, mostly clean products and there's very few vessels, if any, in the spot market today. So we continue to see price appreciation there.

How does the recent collapse in gas prices, natural gas prices, impact gathering volumes? And where is this impact felt the most on your system?

Yes, I would say, the dry gas basins, any gathering systems that are supporting the dry gas basins are probably the most immediate impact -- where we'll see the most immediate impact. And so we are starting to see volumes roll over a little bit in the Haynesville. Although longer term, I think that's a strategic place where we're going to need to have volumes growing to support the export market, I think with the price signals that are being sent right now, are not stimulating activity there. That's probably the single biggest area, I would say. Oklahoma has been on a slow decline; North Texas as well. But as far as from a portfolio perspective, that's probably the single biggest area. I would say overall, though, we were fortunate and blessed that the most -- majority of our gathering systems are really either -- or associated plays. And so we're seeing still good opportunities up in the Bakken and Altamont. So we see upside potential there in this environment.

Yes. And obviously, we're -- we've got customers there who are sitting -- in the dry gas plays who are sitting on some very good rock, and they're dealing with, obviously, the headwinds with the current natural gas price environment and we pay a lot of attention to that. As Kim said, every week, we talk about the capacity they hold, the value of that capacity. We watch our credit, et cetera. But as Tom said, ultimately, in the projections that we talked about in my part of the presentation, which showed nice recovery in growth in the Haynesville and the Northeast eventually, but clearly, the current gas price environment, it looks fairly persistent. Near-term persistent is a challenge for them and the challenge for our volumes on the non-associated gas plays. All right. Next question is at the current level of CapEx, how do you see EOR volumes trending over the next several years? Jesse?

As we've said before, we focus on value creation, not necessarily investing to keep volumes flat. Absent -- at the current CapEx level, it's pretty consistent with our past performance. We're very capital disciplined in our approach. If the barrels produced don't meet the threshold, we don't invest. Now having said that, we do expect in any depleting resource a moderate decline over time, absent any new innovation or advances in our learning with SACROC and Yates. But having said that, we are working on projects in both those assets that could arrest that decline and potentially even grow some of the volumes in that, so at the current level of CapEx, that's kind of what we would expect to see. Now looking forward, I think we've got some opportunities with CCUS and the 45Q tax credit associated with that. So I think there's going to be growth in other areas of the business. Similarly, shale production, it's -- the current technologies are getting about 10% of the reserve. So I think that adds a potential to introduce CO2 in the future. So I think there are some other opportunities out there that will grow the other parts of the business as well. So I think if we're going to do CCUS in the U.S., obviously, infrastructure is one of the major constraints. I think our system will play a big role in that.

Okay. And my comment, too, on the relative capital intensity or lack thereof on the things we're looking at, no, it's not work ready to promise on in terms of the ideas we're pursuing, but relative to capital intensity.

Oh, you want me to talk about it? Yes.

Exactly.

That's a very good point. Good point, Steve. Yes, I think when you look at our run rate on capital, that $300 million range has been kind of where we've been in the last 5 to 7 years, and you'd probably expect that to continue with the opportunities we discussed.

Okay. Back to the Bakken. In the Bakken, you've added capacity on the processing side that can alleviate the gas constraints. What does this mean for crude production from here? So shifting over to the crude production side of the Bakken, James, do you want to comment on that?

Yes, sure. Actually, that's going to help a lot. With the gas constraints that we saw last year, gathering on the crude side kind of took a little bit of a hit. But as soon as those gas processing plants started to come online, we started seeing everything debottleneck. And so I really expect for the crude gathering volumes to bump up here in 2020 as a result of having those gas processing plants online. I think the other benefit is because we've got the Double H pipeline that takes barrels out of the Bakken down to Guernsey and Cushing, it's going to help the Double H volumes as well. So not only a help on the gathering side, but a help on the Double H pipeline as well.

And I think it, too, will help reduce gas flaring as well as more volumes can flow.

Yes, it has been pointed out, we've kind of been bumping from one constraint to the next out there. It was processing capacity, NGL takeaway. We've added processing capacity. Others have added NGL takeaway capacity there. And clearly, the next wall we're seeing is on the residue gas takeaway. And as James mentioned, by being able to deal with the gas rather than flaring it, are able to unlock some oil production previously sitting idle. All right. Is there a way to repurpose the coal terminals towards refined product exports and interconnect it with the refined products pipeline network?

Potentially, yes. We talked about Pier IX. As long as the demand of 10 million tons of coal is still there, we're going to continue to push it through. It makes very good money right now and there's not a reason to convert it. But you could see it down the road. Our focus has been at our deepwater facility where we've built coal infrastructure. We have a unit, fully capable unit train facility there and access to a ship loader. That's one of the facilities we're looking at piping and connecting to that vast Houston network so that we have the additional dock capacity on the channel as demand continues to grow. We'll continue to look for opportunities on the unit train side, as Steve mentioned. We're running unit trains to Mexico right now at our north of the ship channel facility. There's no reason why we couldn't attract another project to the south side of the channel. We're always looking for the highest and best use for the property. And if there's an opportunity to repurpose it to another use, we'll definitely consider it.

Okay. All right. If Steve gave you each $1.2 billion, how would you deploy it? Just to be clear, that's not happening right here.

Is that personally or? Do you want me to start?

Yes, you go ahead, Tom.

I mean, I think really, a lot of the opportunities that we've been talking about, I think Permian Pass would be one we'd certainly look at and hope to explore it. I think continuing the theme of building out and extending our infrastructure in support of LNG exports. Mexico to some degree as well and just leveraging our Texas-Louisiana Gulf Coast footprint would be, I think, an area where we will bring up many opportunities to the table to consider to deploy capital at attractive returns, but I think that's the key, right? We're going -- I think the theme you should walk away from today is we are going to be disciplined. We're not changing our return thresholds to deploy capital. And so they have to be attractive projects with the secured cash flows with creditworthy customers, and that's what we'll do.

John?

I wouldn't. We don't right now see $1.2 billion worth of projects just sitting there with very good high returns. So we'll be very judicious with it. We think there'll be more opportunities in the Houston Ship Channel. There'll be opportunities that are world-class, ethanol hub up in Argo. There'll be opportunities on the Lower River as it relates to potentially chemical buildout. And so there's $200 million to $300 million a year. And hopefully, we'll find some triples and home runs in there, too, or a couple of hundred million beyond that, but we're not going to do it at subpar returns. They're going to have to be very strong returns with good creditworthy customers, and then we'll look at deploying it.

Yes, Jesse.

Yes. I think sticking with the theme of capital discipline. I think we would look at accelerating some of the development of SACROC and Yates. But ultimately, if it's a $1.2 billion wish list, I'd buy another SACROC.

All right. James?

Really, I'd probably more focus on the Texas assets, KMCC and trying to get it a little more connectivity for exports. When you look at the volume that we've been able to maintain on KMCC, I think in 2018, we were around 240,000 barrels a day; in 2019, we got up to about 265,000, 266,000; and here in January, I think we're a little over 320,000 barrels a day. So connectivity into the Houston Ship Channel on KMCC is where I'd deploy it. Not all of it, but just a little bit of it.

Okay. If 11 docks all in the Houston Ship Channel are underutilized, why not sell some of those docks?

Yes. Well, there's no way we're selling those docks. We could call it lack of foresight. We kind of saw this wave coming. There's not increased demand in the United States in other areas, but it's between 0% and 1%. You're going to have to look to the international markets. And so our customers told us many years ago that we needed to build additional dock capacity, and we built those in answer to it. I fully believe at the 12% per year rates we're talking about, we'll get those full within the next 2 to 3 years and then we'll be looking at the next project to connect, the next 2 docks to add, et cetera, et cetera.

All right. When does the cycle of the negative net recontracting exposure for Natural Gas segment over the last few years come to a close?

So we believe, once we get through 2022, that we'll see a much improved recontracting risk exposure calculation. And really, the drivers in the '21 and '22 period is FEP and -- or sorry, '20 -- yes, '21 to '22 is FEP and Ruby primarily. Those are the biggest drivers. So we think as that -- as we get past those dates, we will see these recontracting risk numbers improve.

Okay. All right. Following up on Shneur's question, what is the exposure from negative net recontracting? I think...

That was covered.

So that's what page?

76.

76. Yes. Okay. One more question out there. What is the New York Harbor storage market environment? And are you seeing IMO 2020 benefits? Probably 2 pieces of that.

We'll start with the IMO 2020. No benefits for us in New York Harbor. Our only exposure to high sulfur fuel was at our -- is at our BOSTCO facility and it's less than 1.4% of our total earnings. So we have 1 project there. To segregate the system, we'll have a high fuel side and a very low sulfur fuel side so that we can keep them segregated. We just, as we mentioned on one of the calls, recontracted with our single largest customer for 5 years a little over a year ago. So we feel it's very solid on a going-forward basis and we'll be able to continue to grow on the very low sulfur side as well as maintain the integrity on the high sulfur side. New York Harbor as a whole has been -- you have to kind of look at each of the markets. We discussed on the analyst call what we were planning on doing at Staten Island, and New York, in its infinite wisdom, put a $0.1375 tax on every barrel of product moving out of that facility, which crippled it. And so we shut that facility down this past year and hope to announce here very shortly conversion into a land sale for the site. Carteret, it's kind of a mini Houston. It has great connectivity into and out of it and it is long on docks. And so the last 2 quarters after the PES fire and shutdown have seen very strong numbers and growth on our import gasoline barrels there. So strong, Carteret; weak at Staten Island, hence, the reason why we shut the facility down; overall, improving post PES.

Okay. That's it for the question and answer for the panel and good questions. Good responses. I hope it's apparent to everybody here how much of the details our business segment presidents are and how focused they are on what's going on in their market, they understand their market and how they're commercially extracting the value where we can. So let the team know if you thought this format was helpful, and it's new for us doing it this way. Let them know if -- let our team know if you thought it was helpful. And now I'll turn it over to David Michels to redo -- to review the 2020 budget for you. Thank you all.

All right. Now what you've all been waiting for: the 2020 budget. So I'll be going through the 2020 budget, which is consistent with what we put out in our summary guidance in December, just with a lot more detail. And as usual, we've posted this to our website, and we'll be referring back to it. We'll be comparing our actual performance on a quarterly basis to what we've budgeted. So Slide 53 here provides you an overview. Our adjusted EBITDA that we expect to generate in 2020 is $7.6 billion, about even with 2019; $5.1 billion of DCF, up 2% for 2019; DCF per share of $2.24, up $0.05 from our $2.19 that we generated in 2019. It's important to note that this growth comes despite the fact that we've sold significant assets in the last couple of years. We've sold Trans Mountain, KML, Cochin. Collectively, that contributed over $400 million of EBITDA a year. And of course, those proceeds were put to good use. We reduced our debt and that's been beneficial to us in many ways. But the sales do drag down our financial growth. For example, putting 2019 on the same basis as 2020, so removing the contribution from those assets that we sold, our EBITDA would be up 3% 2019 to 2020 budgeted, and likewise, our DCF per share would be up about 5% year-over-year on the same basis. We expect to generate -- or, excuse me, we expect to spend $2.4 billion in discretionary capital. We expect to end 2020 with a debt-to-EBITDA of 4.3x, the same as where we ended 2019. And this will be our fifth consecutive year of not having any need to access the equity markets. And our cash flow, our operating cash flow, we expect to nearly cover all of our projected cash flow needs for 2020, including our dividend, sustaining and growth CapEx. Slide 54, our assumptions and highlights for the budget. In Nat Gas, you can see here, this is the main driver of our growth from 2019 to 2020, up 2% year-over-year. Once again, the theme is multiple areas of growth, promoting additional contributions to our Natural Gas segment: full year contributions from Elba liquefaction; Gulf Coast Express; as well as Bakken expansions; we also see growth due to increased volumes and enhanced margins in our Texas intrastate systems. Those are partially offset due to the sale of the Cochin pipeline, which we have transferred from our Products segment into our Natural Gas segment at the end of 2018. So that's a reduction in contributions in 2020. We're also expecting to see some unfavorable recontracting impacts from MEP and Ruby, along with some lower drilling activity impacting some of our volume-based revenue on our G&P assets, as Tom mentioned, in North Texas, Oklahoma and on our KinderHawk assets. Finally, we'll see a full year impact from our FERC 501-G settlement on TGP. Products. We've got steady performance in the Products business. Lower rates expected on recontracting at KMCC and Double H, offset by volume growth across multiple assets, expansion projects contributions in the Bakken as well as on KMCC and tariff increases from our FERC index escalator, as Kim covered very well. Our Terminals business is down 10%, and that's due to the sale of KML. Obviously, our Alberta and Vancouver terminals are in this segment. Outside of the segment impact, the Terminals business would actually be up a couple of percent year-over-year. That's due to expansion project contributions and rate escalations, partially offset by unfavorable recontracting in the Northeast. Our CO2 segment is up year-over-year, 8%. That's due to higher expected realized prices. Our WTI assumption for 2020 is $55, and that is lower than our assumption for WTI in 2019, which was $60, but that's more than offset by more favorable hedge prices in our Midland-Cushing hedges. If you recall, when the Midland-Cushing basis spread blew out, we protected ourselves by locking in hedges for that basis. But of course, those hedges reflected a constrained market at the time of negative $8 per barrel. The negative hedges have now rolled off and our 2020 hedges are more reflective of the less constrained market, and they're slightly positive. Our net oil production is expected to be down 8%, and as Jesse mentioned, that's largely due to not deploying additional development capital in Tall Cotton and in our Katz business. Those 2 fields are expected to decline on a net basis, 15% and 18%, respectively. SACROC is expected to be down 8% and Yates down 3% versus 2019. Our interest expense assumptions, we expect our interest expense to be favorable versus 2019, largely due to our lower debt balance, which resulted from the debt we paid off from the proceeds we received for KML and Cochin sales as low as -- excuse me, as well as lower budgeted short-term rates benefiting our floating rate debt. You can see that we're budgeting here to -- we're budgeting LIBOR, the 3-month LIBOR average to be 1.64%, which is down from an average in 2019 of 2.35%. Cash taxes. Once again, we don't expect to be a material U.S. federal cash taxpayer. Our 2020 adjusted EBITDA, Slide 55, higher by $26 million. Nat Gas is the largest driver, followed by CO2, mostly offset by the KML sale impacting our Terminals business. G&A is up slightly. And then JV DD&A and NCI, these 2 items collectively show a $70 million reduction year-over-year. $65 million of that is our partner's share of higher DD&A and earnings from Elba Island liquefaction, given a full year in service for the first several units. And as a reminder, we consolidate Elba, so that's shown up above on a fully consolidated basis, and this is where our partner's share largely comes out. So taking those items into account, EBITDA is about flat with 2019. And then on Slide 56, we'll go from EBITDA down to DCF. Our budgeted DCF is $5.099 billion, $106 million increase, 2% greater than '19. As I mentioned before, our interest expense is expected to be positive, 106 -- excuse me, $126 million, again, mostly due to a lower debt balance and favorable short-term interest rates. Cash taxes are lower versus last year, and that's due to the sale of KML. KML was a cash-taxpaying entity. Partially offsetting those are sustaining capital, up $28 million, and we'll cover the moving pieces there in a different slide. And then prior to the sale of KML, if you recall, we had accounted for the noncontrolling interests for KML below EBITDA, and that was so that we could match up our fully consolidated balance sheet and debt from KML with a fully consolidated EBITDA. So that's why you could see here the KML NCI adjustments were down below EBITDA, and of course, this year, we don't have any because of the sale. The DCF per share budgeted to be $2.24, $0.05 up from 2019's $2.19. And with the $2.24 and an expected dividend per share to be declared at $1.25, that puts our coverage at about 1.8x or a cash coverage of $2.250 billion, so healthy coverage there despite that robust dividend increase. Moving on to adjusted earnings, this slide is a reconciliation from DCF down to adjusted earnings, and here, you can see the main differences between DCF and earnings. It's cash taxes and sustaining capital. If you add those back to DCF and then reduce book taxes and book depreciation, those are the main moving pieces. Our adjusted earnings per share for 2020 is expected to be $1.01, about a 6% increase from 2019's adjusted earnings per share. Moving on to sustaining capital. Overall, as we mentioned, sustaining capital is expected to be up $28 million year-over-year. Natural Gas is the largest component of that increase at $24 million, and that's additional pipeline integrity work, class change projects and compressor overhauls on Citrus as well as compressor overhauls and some integrity work across multiple gathering and processing assets. Terminals is also up year-over-year, $8 million. That's due to an enhancement of our fire protection assets across our liquids terminals, a pipeline replacement project in the Northeast and some additional dry dock time for our Jones Act vessels. Those are partially offset by lower CapEx related to our KML assets that we sold. Discretionary capital, we're budgeting to spend about $2.4 billion. Natural Gas is the largest component of that, and they're -- the largest projects aren't a surprise, Permian Highway Pipeline, projects on our Texas Intrastate systems to expand capacity across our Gulf footprint, Bakken G&P expansion projects and our EPNG South mainline expansion projects. There are numerous other smaller capital projects that round out the $1.4 billion for Natural Gas, and that's consistent with what we've said before, that going forward, a lot of our projects are mostly going to be focused on, we expect, smaller, higher return-type projects rather than larger, high single profile, high CapEx-type projects. And as you'll recall, in 2019, we spent about $600 million of contributions to our joint ventures to fund our share of debt maturities at those entities, and that was quite unusual for us. We said it at the time and I think 2020 is more representative of a go-forward basis. MEP and FEP no longer have any debt and the majority of our JVs can refinance their maturities as they come due. Products, our largest items, where we're spending discretionary capital and products are our Bakken spend to accommodate additional expected volume, oil volume as well as additional investment in our KMCC connection with Gray Oak. Our Terminals spend primarily relates to projects to expand our services and capabilities in the Houston Ship Channel. And in CO2, our source and transport spend is focused on McElmo Dome and our EOR spend is focused on SACROC projects and purchased CO2. And as usual, and as Jesse mentioned, in that segment -- in this segment, we regularly evaluate projects to ensure we're generating adequate returns. So moving on to our sources and uses. As normal, this is meant to represent a high-level summary of our sources and uses and it does not incorporate a number of working capital items and other certain estimates, but does give you a good sense for what our sources and uses will be for the year. Starting with the uses first. Our expected declared dividend of $1.25 is $2.849 billion; our growth projects and contributions to JVs of approximately $2.4 billion. We also have $99 million of remaining taxes on our Trans Mountain sale. We were able to defer those to 2020. And we have about $2.2 billion of debt maturities this year. This page says $2.3 billion. $100 million of that is our GP preferred security, which flipped into a current maturity when we notified our holders that we'd be paying it off. We paid that off earlier in January. Our sources, $5.1 billion of DCF, $764 million of the cash proceeds that we received from the Pembina stock sale, which closed earlier this year. That would leave us with a need of $1.77 billion of debt issuances during the year. And while we do expect to take advantage of the low interest rate environment and access to debt markets this year, we have plenty of capacity under our revolver, and we can be patient. Moving on to the leverage and liquidity page. We ended 2019, as I mentioned, at 4.3x, and we expect to end there, again, at the end of 2020. Our improved balance sheet and lower leverage gives us more financial flexibility, more financial strength. We're comfortably rated in the mid-BBB level and, at our current leverage, may even put us more in the more favorable part of that rating category. We reduced our credit facility capacity in 2019 from 4.5x to 4 -- excuse me, $4.5 billion to $4 billion by allowing a short-term facility to roll off. We still think we have ample liquidity to meet all of our needs with the $4 billion credit facility, along with our enhanced ability to access the investment-grade market. Our 2020 quarterly profile looks pretty consistent with years past. We don't generate evenly distributed returns. The main drivers of seasonality in our Natural Gas business, where our performance there is bolstered by strong winter demand in the first quarter and the fourth quarter. We also have some tax payments that are focused in the second and the third quarter. And of course, with a growing business, there are more contributions to the business later in the year versus earlier and that's why, generally, what we see in our business is our fourth quarter is typically the strongest, then our first, followed by the third and then the second. So as usual, please calibrate your models accordingly. Our cash tax calculation for the year. As you can see here, we generate or expected to generate a taxable loss in the year of over $1 billion. So we don't expect to be a cash taxpayer in 2020. That, coupled with the deferred tax asset that we already have on our balance sheet, we don't expect to be a cash taxpayer until beyond 2026. And a lot of things can change that timing, but that's the best estimate that we have at this point in time. But as you're familiar, we do have cash tax payments on a regular basis, and that's what the $71 million for this year represents largely to do with our taxable JVs, NGPL, Citrus, Plantation and others. Our Slide 63, Budget Sensitivities, is largely for your reference. But to hit on a couple of the main ones, our WTI and Henry Hub assumptions for the year, $55 per barrel and $2.50 per M. Our direct sensitivities to those commodity prices are about a $5 million impact for each $1 per barrel change in the price of oil and about $1 million impact for every $0.10 change in the price for gas, so pretty manageable exposure there. We also have $8.9 billion of floating debt. That's approximately 27% of our total net debt outstanding. The floating debt has benefited the company meaningfully in the recent years, but that being said, we've reduced our floating debt exposure in proportion with our total debt so that we have less absolute exposure to interest rate fluctuations at this point in time. The rest of the page is for your reference to have all of those assumptions in one spot. So Slide 64, now and then. So back on January 24, 2001, Kinder Morgan, a company that was just a few years old at the time, held its first Investor Day presentation. So that makes today the 20th Investor Day presentation. A lot has changed over those years. As you can see up here, we acquired significant Canadian assets with our Terasen acquisition back in 2005. And now we've sold significant Canadian assets with our sales culminating in December with sales to Pembina. We, of course, acquired El Paso, we've rolled up our MLPs, we converted to a full C-corp. We've also experienced tremendous successes across our business units, where we've developed and established premier industry assets, leadership positions, and our enterprise value has grown by $75 billion. From this point forward, we've added over 8,000 employees, and our income and cash flow has grown significantly. Meanwhile, a lot hasn't changed over those 2 decades, continuously -- we continue to be focused on fee-based assets and prioritize the safe, efficient operations of those assets. And Steve covered a lot of that earlier. The company has maintained its relentless, analytical rigor and focus on details, and you've heard a lot about this today. We've continued to maintain our disciplined capital allocation. We pride ourselves on our transparency with -- to our investors, and that hasn't changed. And management has remained significantly aligned with shareholders. So those 20 years of achievements couldn't have been possible without a lot of support. So thank you very much to our employees, and thank you to our investors for your support over the years. And with that, that completes the 2020 budget session, so we can transition into Q&A.

Yes. Ray, if we could turn on the mics here. Okay. Are we on? Okay. So we'll do the regular kind of "the end of the conference" Q&A session. We're going to use Slido again, is that right? But we also have microphones if anyone would like to do it old school. And we've got a hand up right here in the third row. Okay. Danilo?

Danilo Juvane of BMO Capital. If the business has not selected to deploy the $1.2 billion in free cash that was asked, how do you spend the cash this year?

Yes. So yes, I heard them say that they weren't going to use it all. Look, like we said on the call last week, like we reiterated here today, we think that there is value in having that capacity available on the balance sheet. There's some option value associated with it. But we are also committed to returning free cash flow to our shareholders. And if we don't have good project -- high-returning project needs for it and that is still available, we have the option to buy back shares. We're returning significant value to shareholders right now with the year-over-year consecutive dividend increases. But we have the opportunity, certainly, under our -- the existing program to buy back shares. However, we will continue, as we have, to do that opportunistically, meaning we're not setting out their target price. We're going to evaluate those opportunities and discuss them with our Board, make sure that we're on the same page there. So we're going to be opportunistic about it and just as we have been. So there's really no change in that guidance.

My follow-up question is with respect to the dividend. Obviously, you've grown 25% this year. But to the extent that EBITDA growth long term is lumpy, how do you think about dividend policy going forward? And I'm not looking for guidance, just wanted some guidelines as to how you're thinking about that going forward.

Yes. So as we've discussed, we think it makes sense to have a dividend policy over the long term that is consistent with the underlying growth rate of the business as opposed to a 25% year-over-year increase. And so that's what we would expect. And that's a Board decision and something that we'll continue to evaluate as we get closer to 2021 and putting out guidance for that period and as we evaluate what our real capital requirements are going to be.

Shneur Gershuni with UBS. Sorry for being a little old school with the microphone here, but maybe to follow up on some of Danilo's questions here. With respect to the balance sheet, are you happy with being BBB flat? You're clearly well below the metrics or the leverage metrics that you wanted to be at. You've highlighted that CapEx is 6% accretive. Buybacks is 5% accretive. Is paying down debt further more accretive than either of those 2 options? Do you want to be BBB+? Just wondering if you can sort of talk about how you're thinking about the balance sheet from that perspective.

Yes. It's something we look at on a continuous basis to evaluate what the best use of additional available cash would be. And David will go into a little more of the detail there.

Yes. So generally, our -- where we are in our rating and our leverage, we feel is a pretty good spot and doing much below that really doesn't give us much of a weighted average cost of capital benefit. It does provide cushion and flexibility, which is valuable, and we could utilize that for some option value for us if there's an attractive utilization of that cash flow and that capacity, but it will be opportunistic, I think, is the right way to look at it.

And maybe another follow-up to Danilo's question with respect to the dividend. So I mean even after you do the 25% increase this year, you're still underpaying your dividend relative to your cash flow generation. Is the plan to just completely just step down to the DCF per unit growth rate in '21 and then maybe use the excess cash for buybacks? Or is the thought to sort of linearly bring it down towards the level and eventually ending at your DCF per unit? Kind of wondering what the different options the Board is thinking about and when you expect to update us about it.

Well, let me just say that, as Steve said, we're not going to make any call on the '21 dividend until later in the year when we look see at what 2021 looks like. But as he said, longer term, we're going to grow the dividend consistent with the growth rate in the underlying business. And I think that the 500,000 really here that we referred to several times, is the absolute pay down of debt, $9.4 billion of debt that we've paid down over the last 4 years. So we worked very hard to get our balance sheet in shape, and this management team and the Board is, I think, very fixated on making sure we're returning value to our shareholders. And that's -- we're going to run this in a very conservative way as all the team has said this morning. Right. There's one in the right.

Jean Ann Salisbury from Bernstein. Two asset-level questions. One is just another follow-up about the Natural Gas pipeline recontracting in Slide 76, which you flashed on the screen earlier. I think you've said before that those exposures for 2021 and '22 are based on, like, Ruby's basis, which is obviously very low. I'm assuming that you're now having early conversations with customers. I'm just wondering if they're indicating that they're willing to pay materially above the basis to secure capacity.

Yes. I mean, I think it's still early days, but, I mean, we are valuing the capacity of what we think the market is at that time. Clearly, there are some customers induce -- LDC-type customers that may pay more than what the basis is. And we think there is some intrinsic value, extrinsic value in the capacity as a whole. But that's really the major -- even with all that, though, the market rates, we believe, are lower than clearly what we have on the current contracts, and that's really why we have the recontracting risk shown the way it is.

Okay. And then I just wanted to make sure I understood the chart on Page 113. So if EOR production -- you'll probably extend it a little bit versus this, but if EOR production does kind of fall in that fashion, would CO2 usage also fall kind of materially and you would expect after the take-or-pay contract for that part of the business to fall as well?

Jesse?

I think from an equity standpoint, if you -- this chart here is the one we consistently push out. From an equity standpoint, that's correct. I think we have longer horizon contracts with third parties that would keep that side of the business relatively flat.

Ujjwal Pradhan of Bank of America Research. A question on M&A. How should we think about what parameters you would consider in approaching any M&A opportunity? And would it be more focused on Natural Gas? Or would it be maybe thinking more along diversification?

I think that the watchword, again, is we're going to be conservative and particularly conservative with all the work that we've done to get our balance sheet where it is. We're not in a hurry to do something that would restart that clock or restart that effort. When it comes to what we look at in M&A generally, we're still -- we still look. We did a very small -- single asset acquisition kind of at the end of last year. We still look at those things, but we want to see attractive returns, very attractive returns, particularly as compared to our other alternatives for the use of the cash or the capacity. But we don't say, hey, we need to have this position in this geography for this commodity. We look at whether it's something that we're comfortable with, accustomed -- comfortable with operating, accustomed to, things that asset or a situation where we could bring value to the table. We can bring cost savings, synergies, commercial synergies, capital synergies, et cetera. And so it's more does it make it through the screens of economic value creation as opposed to, say, focusing on a particular region or area or a particular business line. If it's in a business line we already do, that gets us comfortable with some of those questions. But again, if you go back to what you've heard over and over again, is how disciplined we are with the capital and the capacity that we have and we're going to want to look to use that capacity opportunistically to create additional value, enhance the value that we've created for shareholders beyond just having the capacity itself.

And maybe a quick follow-up on LNG opportunities. Can we see another project like Elba Island? And maybe if you can update us on the Gulf LNG project as well.

Okay. On Elba Island, as I said, I think the market for long-term contracting, securing our cash flows and the way that we like to contract, in the way that we like to run our business and the lack of exposure to global natural gas commodity prices, that really is not an existing opportunity, right? You'd have to take, I think, more risk than that. There are people who are in that business, who are comfortable with the risks and mitigating them. You'd have to take more risk in order to be able to do that. So it doesn't look like the opportunities that are really available in the LNG market as it exists today are there. We're happy to have the Elba opportunity. We do have an opportunity on that island to further expand the capability at that facility. And so we would look at that if our customer was interested and if the economics worked for our shareholders. With respect to Gulf LNG, I wouldn't expect anything anytime soon there just in light of the situation right now for U.S. LNG. So I think that's just not a likely thing to develop in the near future or the medium term.

Jeremy Tonet, JP Morgan. Maybe just following up on some of the earlier questions of capital allocation philosophy. I was wondering if you could kind of walk us through historically how hurdle rates have trended. It seems like there's been a lot of talk about high grading capital. I'm just wondering if you could update us on where that's been before, where it is now and how that kind of varies across the segments.

Okay. So we started self-funding in the first quarter of 2016. And when we did that, we high graded, if you will, what we were looking at in terms of projects or potential projects, really. And we elevated our return criteria at that time to something significantly above our WAC and reasonably so, I think, because we were self-funding those projects largely and we have continued to do that. I wouldn't say there's necessarily been a lot of evolution in that hurdle rate since then. What we have done really all along is if we have a good risk-adjusted return on a project where the cash flows are secured by long-term contracts on a take-or-pay basis with creditworthy customers, like the situation we have on GCX and PHP, we're not getting a 15% unlevered after-tax return there. We're getting a good double-digit unlevered after-tax return there and well above our weighted average cost of capital, but we dialed it down in the face of a reduced risk. And so we continue to evaluate projects. And I think all of our business unit presidents know that if it doesn't hit 15%, that doesn't mean let's not talk. If you've got something that you feel very strongly about because the risk has been taken out of it, then we will evaluate those projects. And that's kind of the way it's been really through that last 4-year period really. So it hasn't changed much since then. And part of the policy is due to the early retirements. And actually, we have boosted a bit on the gathering and processing assets that we look at as well because there is more volumetric and in some cases, commodity price risk. But having a well-covered dividend, like we have today that enables us to fund at least the equity portion and really significantly more than just that portion is a good position to be in. And it's a place we've been in really since -- starting 4 years ago.

And I think another thing that shows the conservative approach, Steve and the team have done a good job, for example, of looking at the terminal value on these assets. Tom referenced this earlier, that, of course, what we're seeing on some of these systems have been seen is as a very nice contract rolls out -- that rolls off after 10 years, the recontracting is at a lower rate. So what we're taking into account on all the projects now is looking at terminal value, with assumption -- varying assumptions on what you can release that capacity for at the end of that period of time, which also plays into how you look at whether a project makes sense on a long-term basis.

And I don't know if there's anything else you can share on the philosophy as far as the different hurdle rates and when you think about share repurchases, kind of like different share prices versus the hurdle rates or just any other kind of framework in general. I know you guys want to be very kind of nimble in any share repurchases, but just trying to think through how you guys look at the process.

So we look at it on the basis of returns. And I'll ask Kim to jump in here as well. We look at it on the basis of returns. There are different investments, obviously. If you're repurchasing stock, you're repurchasing a levered entity, but a very diversified investment. And so you have less risk associated with that; whereas on a capital project, we're looking at those unlevered returns typically. And there's a single project risk. However, when we do -- we look at it in a number of different comparisons, assumptions that there's multiple expansion and share prices go up or that there's not, we normalize between the levered and unlevered returns. And what you typically see is a project even at like 12.5% unlevered is going to produce a high 20s kind of return. And so at least not assuming a multiple expansion, it's a more favorable return opportunity. The other thing that we take into account is that, look, if you look at an individual project by itself, that's got a fair amount of risk associated with it on just that individual project. However, our overall capital program, if you look at that in aggregate, the returns have been superior to what you would get in most normal assumptions around the share repurchases as Kim showed on the look-back chart. So look, if we've got good NPV positive, with a good margin of safety above our cost of capital, it's going to make sense to invest in those. But again, we're not going to force it, and we're committed to returning excess cash generated to shareholders, which we're doing through the dividend, and which we can continue to do share through share buybacks. But we evaluate them. We evaluate them based on return, and another reason for us to be opportunistic in our approach. We have a high-tech question. What are the bookends of possibilities, how KMI might be affected by the presidential election this fall? And how are you working with the industry to educate key people? Obviously, we don't know how it's going to turn out. The thing that's been most -- most of the headline has been around a couple of the democratic candidates, announcing a frac ban and trying to supersede one another with how fast they're going to initiate it and how widespread it will be. We've done some analysis to see what the impact of that would be on our customers and therefore, indirectly on us, and would expect that, that response would be more muted maybe than people anticipate because there's likely to be some shift in where the production comes from, focusing more on, say, private lands rather than federal lands or on tribal lands rather than either federal or private. And so we see some moving around in where the production would take place. We would also hope, and I'd say, again, this goes to the practicality of our approach to climate change and how that policy debate evolves and changes over time, we think the benefits that natural gas produces when closely examined by whoever occupies the White House, you can't help but conclude it does a great deal for our domestic economy. It does a great deal in terms of jobs, in terms of the portion of the manufacturing sector that's dependent on it. It does great things for our trade balance and it does good things for the climate, and for just pollution levels. And we can do that worldwide. What we would hope and what, I think, the trade associations in Washington and others, elected representatives and others will focus on, is taking those benefits into the account before doing something definitive.

Michael Lapides with Goldman. Two separate questions. One is when you look at your business mix, outside of the gas business, how do you look at the other businesses? And when you talk to the Board about the mosaic of what -- kind of whether there are further opportunities or there are further potential noncore assets or even entire segments within the mosaic of Kinder Morgan. That's my first question. Second is entirely unrelated to it, which is if you had to look at any of your businesses or even the major assets and say, which 1 or 2 are potentially under-earning what you think the level -- the potential level kind of long run would be, what would those be?

Okay. As usual, Michael, I have to write your question down. Okay. In terms of the business mix and the opportunities, look, a lot of that revolves around refined products in both James' and John's business. And so we have contract escalators in our Terminals business. We have tariff escalators in our Pipeline business, and so we see that sort of noncapital-driven growth opportunity there. The overall picture, there is obviously about 1% year-over-year growth. And so that suggests lower opportunities for additional growth investments. But there are -- that is a case-by-case inquiry, as John described, we've got opportunities still to come in the Houston Ship Channel. That 1.5 million barrels a day that Kim mentioned, I mean, put that in the context of what 18 million barrels in total in the U.S. refined products market, and the unutilized capacity to allow us to do more further exports and we're serving the refineries that are cost advantaged, the most cost advantage in the United States. So there will be those opportunities around the table, but they're not necessarily the really big chunks like a PHP project, for example. So some organic growth, some relatively modest opportunity for additional growth capital investment and that's how we describe it when we're talking to the Board and when we're looking at the slate of opportunities that's out there. And as we're looking at those, I mean we take into account at terminal values. I mean, the electric vehicle market penetration has been slow -- slower maybe even than anticipated. It takes a long time to roll over that fleet, but you don't assume an infinite life. You look -- you stress test it in terms of putting a 0 TV out there somewhere just to -- not that we believe that, but just to make sure that we are getting an adequate risk-adjusted return. On your second question, I didn't quite get the conclusion there. Which 1 or 2 of our businesses do we think are under-earning. Is that what you said?

Yes. When you think about what normal would be or what potential growth rate in the earnings piece, which assets do you think today or in your 2020 guidance or which entire segments do you think are under-earning the long-run potential level?

Yes, I'm not sure that -- if we look at our returns on invested capital, I mean, I think overall, while that's come down in time with commodity prices coming down, I think we're generally earning good returns on the capital that we've invested if you take the DCF that's being produced by the total amount that's been invested in those businesses. We do look at where are there places where assets are more valuable, potentially in the hands of others than they are in our hands. Somebody might be willing to invest a lot in a gathering asset, for example, that we would be more judicious about. We look at that. John continues to look at his bulk assets. I think he's -- over the years, that's been pretty well trimmed down to assets that we feel very comfortable owning and operating. So I think if you look past a big transaction like KML, which had a lot of other considerations around it, we continue to look for where those opportunities to sell assets that might make sense to sell and redeploy that, whether it's in share repurchases or in other projects. I think it's reasonable to think about those as being relatively small bore. They're not big chunks.

And I think the other thing you have to keep in mind when you talk about opportunities in these various non-natural gas segments, let's not forget the cash-generating capacity. If you just look at Products, for example, with about $1.3 billion of EBITDA and reached a sustaining CapEx of less than $100 million, a run rate of maybe $150 million to $200 million in expansion CapEx, growing slightly, you're bringing a lot of cash flow to the bottom line. And certainly, we don't overlook that. And we realize the cash that James' and John's operations are providing as well as Jesse's on the CO2 on a free cash flow basis, as we showed you on one of those slides.

I think the last disclosure that you gave on cash taxes, was that you expect to be a cash taxpayer the middle of this decade. How dependent is that on you guys spending $2 billion to $3 billion of growth CapEx per year?

Yes, it's a good question. Obviously, bonus depreciation goes a long way in shielding our taxable income. So it does have an impact. The bonus depreciation, utilization -- or the bonus depreciation level of 100% ratcheting back down does fall off in the coming years. So it will have less and less of an impact going forward than it does right now. But it's definitely a driver of the depreciation and we get to depreciate against our taxable income.

But even with that, David, we're comfortable in the beyond 2026.

We are. Yes, that's right.

Okay. And then the second question I had, I just wasn't clear from the presentation. When there's debt coming due at your JVs, I think that's technically -- and you pay it down, I think you guys classify it as contribution to the JV. So is that spending classified in your discretionary CapEx or debt paydown?

It's discretionary CapEx. And that's -- it's just -- the whole bucket of contributions to our JVs is just how the way that we look at cash on cash-type returns. That's cash contributions to those JVs. And when we compare that to our cash received from our JVs, it's the total distributable cash flow capabilities of our interest in those JVs.

Durgesh Chopra with Evercore ISI. Just to follow up on the liquid indexation review. I know we touched on the deferred tax reform being the wildcard there. But FERC, as you know, already has an ROE, ongoing ROE review for the natural gas and liquid pipelines. Any update on that front?

Update on the ROE valuation that FERC is doing, I mean, I think, our view is that natural gas can or should be and we expect will be treated differently from the rest of the regulated industries under FERC control. I mean if you look at -- if you contrast an electric utility with a franchise and a protected franchise with cost pass-through assurance and a mature assurance, that's a different picture than the really the competitive and largely market-based environment in which natural gas auctions. And I think the commissioners recognize that distinction. We don't have a franchise, okay? We compete with each other in that market. And that's a function of commission policy dating back over 30 years from all kinds of administrations. They've increasingly moved that business into a competitive -- more of a market-based environment. So we would expect that the commission is going to evaluate on any policy going forward on ROE, taking that into account, meaning look a little differently at the electrics than they do at natural gas. But there's not really much in the way of an uptake there. I think the commission gathered a lot of -- and they did this in the certificate proceeding, too, when they were taking comments on advising their certificate -- revising their certificate policy statement. They took a lot of information in, but then it didn't translate into some broad-sweeping rulemaking. I suspect we'll project that what will happen is they'll incorporate it as they look at individual cases.

And then just a quick follow-up one for me, guys. Is there a targeted level of ownership there? Or just given your backlog, could you possibly do it all by yourself?

Yes. So we own is -- on our 2 Permian pipes, on one, we own 26.7%. On the other, we own 34%. I mean, we would have like to own more in each of those instances. But if customers are coming with big volumes and they want equity, too, we're certainly going to do that. I think governance gets more difficult when you get down into the low 20s or 20 range. And so we have to be mindful of that. But we would like to own -- we'd certainly like to 1/3 of it on the next project. Okay. Oh, there's another question over here.

And just a fast one. Pearce Hammond with Simmons. How does consolidation in the E&P sector and the potential wave of additional M&A producers impact your business? And does it change the competitive dynamic in negotiating with your customers?

Well, I'll start and Tom can add on. I mean, generally, credit quality can improve in a consolidation environment. And then the second part of your question is does that change the negotiating dynamics? I would say not materially. Well, Tom, why don't you comment on it?

Yes. I mean, it's case-by-case, but I don't think it materially changes the dynamics. I mean, we've seen instances where we've had sort of a single-purpose producer get consolidated with a larger producer. And so they allocate their capital differently, and that's either had positive or negative effects in some areas. But overall, high credit quality and the ability to deploy capital and transact, I think is a positive for us, and we think that's what happens when we see consolidation. So that's what we would expect to see going forward.

Okay. I'm not seeing anything else on the screen or out there. So thank you all very much. And I would like to thank our team here. Many of them are people you know, Anthony Ashley, our Treasurer and Head of Investor Relations; Chris Graeter, from our Treasury Group; Ashley Zavala -- your name has to be Ashley to work in this group, one way or the other; Hannah Stuckey; Peter Staples; and Mindy Thornock, if we could show some appreciation. So they work very hard and hear your questions and try to make sure that we're being transparent and incorporate the information that you're seeking. So I hope you find that the presentation was good. Now are they ready for us for lunch? We're a little ahead of schedule here. Let me talk about the format on lunch. So we're going to have different tables set up in there. And so Rich and Anthony are going to be at a table. David and I are going to be at a table. Kim and Dax are going to be at a table, and the business unit presidents will each have a table and probably 1 or 2 of their folks there. And so you can pick who you want to eat with and who you have questions for. And so that's the way we're going to be set up. And the rooms are Zavala 2 and 3, correct? Okay. So they're the ones that if you go out this door here and you go to your left, you'll see them on your left as you're walking out. And they may still be setting up in there. So if you got some phone calls or something, go ahead, but we'll be -- we should be ready to go shortly for lunch. Thank you all.