I'm Rich Kinder, Executive Chairman of Kinder Morgan, Inc. And before we start our presentation, the hotel wanted us to make a couple of remarks, one of which is to tell you that the hotel is being renovated. I'm sure no one picked up on that. But so be very careful when you walk and step and avoid slip, trips and falls. That's important.
Exit locations are these 3 main doors. Restroom locations, more important news, for those of you who've been in the past, are now down to the left, down the ramp as opposed to right here where they used to be. I thought this was interesting. The hotel was nice enough to say that there is no fire drill scheduled this morning, so we can rest assured. This morning, we've got a good presentation for you, I think.
Steve and Kim and the team will do all the heavy lifting today. But I want to spend a few minutes talking about KMI as an investment opportunity. We've made enormous progress over the last 3 years. As I said on the recent quarterly analyst call, over those last 3 years, we paid down over $8,000,000,000 in debt, reducing our debt to EBITDA level to 4.5, which is our target, and led to an upgrade from both Moody's and S and P. We raised our dividend from $0.50 in 'seventeen to $0.80 in 'eighteen and have reiterated our intention to increase the payout to $1 this year, 'nineteen, and $1.25 for 2020.
We've also funded all of our expansion CapEx with internally generated funds, and we bought back over $500,000,000 worth of stock over that period of time. Continue to generate strong cash flow, and that cash flow is growing. In my opinion, that makes KMI stock a unique and pretty compelling investment opportunity, but let me show you why we feel that way. If you look at Slide 6, as our targeted debt level has been achieved, we can use our distributable cash flow for expansion CapEx, dividends and stock buybacks. This slide shows how our DCF has grown from $4,500,000,000 in 'seventeen to $4,700,000,000 in 'eighteen and a budgeted $5,000,000,000 in DCF in 'nineteen.
Even when taking into account the fact that we are increasing our dividend to $1 this year, we will still have dividend coverage of 2.2 times and we'll have about $2,700,000,000 to invest in new projects like our 2 new pipelines which will move in total over 4 Bcf a day of natural gas from the rapidly growing Permian Basin. Looking at this chart in a different way, you can see we have generated over $10,000,000,000 after dividends in the last 3 years. Going to the next slide, Slide 7, we believe we should be a core infrastructure holding. These are some of the characteristics of being a core infrastructure holding in my opinion. First of all, we're a liquid stock with a market capitalization of around $40,000,000,000 which makes us one of the 10 largest energy companies in the S and P 500.
We have investment grade rated debt and we recently upgraded the BBB, BAA2 by S and P and Moody's respectively. We expect about $7,800,000,000 in adjusted EBITDA in 2019. And as I said, we expect 25% growth in dividends in both 2019 2020, going to $1 this year, dollars 1.25 next year. Our board has previously authorized a $2,000,000,000 stock buyout program. And since December of 'seventeen, a little over a year ago, we have bought over CAD500 1,000,000 of stock pursuant to that board authorization.
Seems to me that all those facts point to a healthy company with a good track record and the potential in a real way to deliver good results in the future. But KMI does not exist in a vacuum. If you go to Slide 8, this slide shows the projected growth in energy demand between now and 2,040 and is set forth in the 2018 IEA World Energy Outlook. What does it show? It shows that natural gas and petroleum demand is expected to grow for decades to come.
This growth is driven largely by developing economies with India's demand expected to double and more and China projected to be the largest importer of both oil and natural gas. There's a combination of population growth, urbanization and economic development, which creates a tremendous need for affordable and reliable energy sources. I think an interesting factoid on this slide is that according to this IEA study, over 650,000,000 people around the globe will still lack access to electricity even in the year 2,030. So a pretty compelling story of globally the need for energy is growing. Now in the midst of all this projected global demand, the U.
S. Is the largest oil and gas producer in the world. The figures are staggering and some of them are here on this slide number 9. Current estimates of U. S.
Proved reserves are at record levels and double what they were 10 years ago. By 2025, this country is projected to produce almost 1 5th of all the oil in the world and almost onefour of all the natural gas in the world, with production expected to increase by 33 percent over this period of time. Now we are advantaged versus other producing countries because we have a competitive market place which drives innovation. We have relatively stable regulatory environment and we have a rule of law which works. This gives us the advantage over other producing companies countries around the world.
Now connecting all these massive U. S. Supplies to growing demand markets, both domestic and foreign, will drive the need for new energy infrastructure and even higher utilization of existing assets. Now let's look specifically at natural gas. This is the area where we are the biggest midstream player, and it's a key driver of our future growth and success as you will hear from Steve and Kim and David Michaels later today.
The growth in demand is pretty dramatic and projected to continue for years to come. Let's start with our current environment. As this slide shows, the growth between 2017 2018 was a pretty astounding 9 Bcf a day or 12%. It grew from about 81 Bcf of demand to 90 Bcf a day of demand. According to the latest Wood Mackenzie study, demand is expected to grow by a whopping 29 Bcf a day between now and 2,030 or 32% growth.
This present and future growth is being driven by increased use of natural gas for U. S. Exports, power generation, industrial and petrochemical purposes, exports to Mexico and even a little bit of growth in the residential demand category. All of this expanded demand has to be connected with our growing supply basins, and that's where midstream companies like Kinder Morgan are key. Our network of 70,000 miles of natural gas pipelines, which moves about 40% of all the throughput in this country, is uniquely positioned to maximize our current capacity.
That's important and it's also important that that infrastructure advantages us for new expansion and extension opportunities off of the base system that we have. Now turning to Slide 11, generalist investors obviously have a wide choice of where to put their money. So why invest in energy infrastructure? This slide shows what we believe are important characteristics of our long lived hard assets when compared with other investment opportunities. Now this is a busy slide, but I would emphasize the long lived nature of our assets, the high barriers to entry, particularly in these litigious times and the significant reliable cash flow generated by these assets and return to investors through dividends, A pretty compelling story we think for the attributes of energy infrastructure in America today and for the foreseeable future.
Now if you choose energy infrastructure, why does KMI make sense within that group as an investment? You've seen this slide or something similar to it many times, but it just shows the strength and breadth of our network across America. We talk a lot about our 70 1,000 miles of natural gas pipelines moving about 40% of the gas consumed in this country and probably more importantly, connecting every important resource play with key demand centers around America. But we also have products and liquids pipelines that move about 1,700,000 barrels of refined products a day and additional quantities of crude and NGLs. We have over 150,000,000 terminals handling liquids and bulk materials, which makes us the largest terminal operator in America.
And we have a CO2 business that transports about 1.2 Bcf a day of CO2 that's used by our operation and others to produce oil in the Permian Basin. So if you think about it, we're really a leading infrastructure provider moving multiple critical energy products across this country. I would again emphasize the tremendous value of pipe in the ground as I think you all read the headlines every day and you know it's increasingly difficult to permit and construct new infrastructure, particularly in those areas like the Northeast where you have tremendous demand and not much appetite for additional infrastructure to be built. Now let me close with one final comparison. Where does KMI fit within the S and P 500 in terms of what I review as key financial metrics.
This slide reminds me of Dickens, the tale of 2 cities and his famous opening lines, it was the best of times, it was the worst of times. On the left side of this slide, the pyramid shows that there is no other company of our size with our credit metrics combined with our growth and our dividend yield. So the right hand slide should show we are valued accordingly, right? Makes sense. Tale of 2 cities.
Wrong. Our enterprise value to EBITDA is 9.6 versus the average 15.6 for the S and P, and our dividend yield is more than double that of the S and P 500. We believe that valuation level provides a lot of upside potential with a strong dividend yield as support. Now I've been telling the same story for quite a while. And the other day, I said to my wife, you know, sometimes I feel like Churchill during the wilderness years when he was complaining about Hitler and German rearmament and nobody was listening.
And she looked at me and she said, well, maybe comparing yourself to Churchill is not a good idea. How about Rodney Dangerfield? So Rodney Dangerfield or Churchill, whatever it is, we recognize seriously that all of you equity investors will make your own decision on whether to invest in KMI. But in making that decision, we would urge you to consider the information we are sharing with you today, which I believe demonstrates that this company has made enormous progress over the last few years and is poised for a very bright future. Thank you, and I'll turn it over to Steve.
All right. Good morning. So I'm going to talk a little bit about our approach, then I'm going to talk about our approach just to how we manage this company. And I'll talk about our business, go through all the segments, but with some special emphasis on natural gas, what's going on in the market there and our projects and how we're exploiting those trends. Kim is going to cover the cash flows and how we've secured them.
She's going to talk about our investments and our track record on those investments, the capital we've invested and how we've done on those projects that we've invested that capital in, how we think about capital allocation. Then David Michaels is going to give you a riveting presentation on the 2019 budget. And Dax will take you through KML, both the business as well as the budget for 2019. So I think that our strategy is really manifested in the long term choices that we've made. Number 1, the sector that we're in.
We're in North American energy midstream. Secondly, how we capitalize ourselves. We're conservatively capitalized, a strong balance sheet mid BBB rated in light of the 2 recent upgrades that we've received. Our commercial model, we're primarily fee based and take or pay. So what we're doing is getting our cash flow secured in the way we approach our commercial business, getting our cash flow secured so that we're not taking commodity risk and we're not taking in large part, we're not taking volumetric risk.
So what our commercial model is. And thirdly, how we manage. We manage to be a safe, efficient, reliable operator. We have discipline in our capital allocation, discipline in how we manage the company. We run this place like a machine.
We regularly every Monday we get together and we look at our financial outlook for the month, for the quarter and for the year. So we're seeing we're having an objective discussion about what's going on in our business, a numbers based discussion, so that we can identify opportunities, identify risks and act on them. We do that every week, so there's no drift in our ability to our acting on the risks and opportunities as they emerge. Every quarter, we review with our business what's going on in each of our business units with their markets, what's going on, what our strategy is for attacking those opportunities. We regularly update how we're doing operationally, how we're doing on safety, how we're doing on compliance, how our major projects are coming along.
We do this in a very routine and regular way, again, so that we don't experience drift. We manage this company, all of its assets and operations and all of our commercial activities and our financing activities and investment activities with discipline. I think it's important that investors as you're thinking about the long term understand how the company works, what its culture is, how we go about making decisions, etcetera. And I think the fact that we approach this business the way we do should be reassuring over the long term. We can deal with changes in our environment.
We react and adjust to those changes, and we do it in a very regular way, again, so that things don't drift on us. If you look at our ownership structure, the management and the Board are heavily invested in this company, 14% management and director ownership of KMI and translating through the 70% ownership in KML that KMI holds, management and the Board are heavily invested in the company. Our interests are aligned. What does that mean? That means we think for the long term.
Our decisions are based on economics, not what's in fashion or what the current flavor of the day is. We're thinking for the long term. We think, deliberate, decide and act like owners of the company because we are. So this is who we are, how we operate and now I'm going to get into a bit of the business. Focusing on natural gas, so large supply growth, particularly in 4 key basins, these happen to be basins we're connected to, and large market growth, and these are markets that we are largely connected to.
The supply growth and the demand growth that we're seeing is unprecedented year over year from 2017 to 2018 and '18 and another big jump in 'nineteen and 'twenty are expected. And to get this stuff from where it's being produced, process it, transport it, distribute it requires midstream energy infrastructure. There's really no practical alternative to moving natural gas except pipelines. They're the safest way, the cheapest way, the most environmentally sensitive way. And practically and physically, there's not a truck or rail alternative.
You need pipes and we have the best pipeline network in North America. So looking at some of the basins here Marcellus and Utica projected to grow over the whole supply basin here or supply basins, growth of over 30 Bcf or 37% through 2,030, again concentrated in those 4 basins. On the demand side, massive growth in LNG, power and industrial demand, we'll dig into each of those and how those affect our assets in a bit. On LNG, in particular, looking at that 3 Bcf a day average for 2018, we ended 2018 at 4.5. Looking at the production that's coming along the LNG projects that are coming online throughout 2019, The capacity is expected to be 9 Bcf, so we could triple what we did in 2018 by the time we get to the end of 2019, massive amount of growth.
Power demand is growing and talk about that in a little more detail as well. So growth on supply, growth in demand, growth that's happening in North America at really unprecedented year over year levels in our infrastructure, our assets are what's required to get it from where it is to where it needs to be.
All
right. Domestic consumption is increasing, so on power and industrial, but increasingly U. S. Gas demand is export driven. Global LNG is expected to grow from 40 Bcf to 75 Bcf by 2,030 and with our resources priced in the $3 an MMBtu range, we'll be competitive for those markets globally.
Few things about LNG. The demand changes take place in big chunks, and we're going to talk specifically about Texas and our opportunity there in a moment. It plugs us into a global market, which means we'll be more subject to what's going on internationally in terms of gas supply and demand. And as a consequence, again, the need for infrastructure in balancing those requirements is going to be critical. So we see a lot of growth coming here over the visible period of the next few years.
Net LNG exports expected to increase to 4 Bcf a day by 2,030, again getting to capacity of 9 Bcf of what is actually getting built coming out of the ground to be commissioned over the course of 2019, reaching a total of 9 Bcf. So, how do we participate in this? We participate, I think, in a very low risk way. We've got the infrastructure that serves those export facilities. We wrap ourselves right around them in Texas and Louisiana.
We serve those markets and we serve them with our domestic assets. We don't participate in the global LNG market. We don't take the commodity risk. Even where we're building a terminal at Elba Island, what we're doing is contracting that under a 20 year terminal use agreement with Shell. We can make a lot of money in the LNG business by providing the services to the LNG market without participating in the global risk and the commodity risk that goes with deeper participation in those markets.
We made a lot of money in Mexico, for example, without really being in Mexico. And that's a great way to participate. We build the assets that get the stuff where it is. Others take the risk and reward of commodity price changes and global risk. For power generation, we're also seeing growth there.
And look, there's a lot of talk about renewables, but I think if you look at any reasonable projection over any reasonable period of time, natural gas is going to play a significant and actually an increasing role in power generation. While there is not there are not plans beyond 2021, at least published today, to add a lot of new natural gas generating capacity, nevertheless, natural gas as both a share and as an absolute quantity is expected to grow in its use in the North American power sector. It's reliable. It's a good backstop to additional intermittent renewable capacity. It's cheap, it's clean, it's affordable.
So natural gas is going to play a role in this over the very long term. It's also been critical to meeting climate change goals. In the power sector over the period from 2000 and 5 to the most recent year for data, it's available 2017, we have seen 23% emissions in the power sector for greenhouse gases. If you look at the overall greenhouse gas emissions, all sectors for the United States, it's decreased by 11% over that period. Natural gas in power generation and natural gas in use generally has helped us bring greenhouse gas emissions down while over a period where the economy has grown dramatically and our population has grown dramatically.
Natural gas is helping to solve this problem. There's a lot of hollering going on out there, and we're just kind of busy solving the problem. Industrial demand growth. So natural gas and its derivatives are used. Natural gas is used to power it's used as an energy source in petchem facilities and industrial facilities.
Its derivatives are used to make stuff. And we also see natural gas intensive industries like fertilizers continuing to grow, dollars 200,000,000,000 of projects along the Gulf Coast of the United States. And these are all the things that are made. These are basic inputs into consumer goods and industrial applications and you can't make this stuff with windmills. So whether we're talking about power generation or whether we're talking about global demand for natural gas or whether we're talking about basic materials, essential things that we need for our daily lives and in all of our manufactured equipment, natural gas is key to that.
And you can see, again, dramatic growth in a reasonably foreseeable timeframe there associated with us having this cheap resource. All right. Gas demand is concentrated in the Gulf Coast. That's important for a couple of reasons. It is where our network is the thickest, right?
It's where we have a lot of our interstate natural gas pipelines as well as a very large intrastate position in Texas. The second aspect of that has to do with the Texas And in between, we're building pipelines and we're connecting up a network that is in Texas. It's regulated in Texas, meaning it's easier to get things done, it's easier to get things built. We don't have cost of service rate making in Texas. What we have is a market based system.
So what we do, we do with our customers in a value for value exchange without the interference or management by the regulator. It's a great opportunity for us to make money. We've got on our Texas Gulf Coast system, it's about a 5 Bcf a day system today, could peak at 7 Bcf. We're bringing with our projects 4 Bcf to that system. That's going to create tremendous opportunities for us.
So a lot of growth happening on the Gulf Coast in particular, 70% of it overall and a little less than half of that is in Texas. And whether it's Texas or Louisiana, it's right along our interstate and intrastate network. So LNG export demand growing by 13 Bcf over this period 18 to 30, industrial demand growing by 2 Bcf exports to Mexico expected to continue to grow, etcetera. This is a good place for us for this development, this growth to be happening. All right.
And so this is the network that makes it happen. We're connected to all the major supply basins, particularly the growing basins, and we're connected to And this growth, I don't remember in over a 30 year career seeing that kind of growth, double digit growth in our natural gas demand in the United States, including export demand from 2017 to 2018. And another sizable this is an area that used to grow at 1% to 2% a year, something like that. And what we're seeing is double digit growth and then nice chunk of 6% growth each on top of that over the next couple of years. And we have an unmatched network.
So gas is growing, gas has to move by pipeline, and we have the best transmission and storage network in North America. And that drives both the utilization of our existing network. So we have had a lot of capacity previously unsold that we've been able to sell over the last 2 to 3 years. We've had the opportunity to see particularly on our big network system that there are exceptions to this. Some of our basis pipes are not going to see good rollovers, but our big network systems, we've started to see some improvement in our rollover both price and term.
That's evidence of how this growth in natural gas supply and demand feeds the value or increases the value of our existing network. It also creates project investment opportunities. And very importantly on this, I mean, there's a lot of capital chasing midstream energy projects. Private Equity, private capital likes our assets better than you all do, okay? We're still trying to figure that out.
You know? But in any case, there's a lot of capital running around out there and it would be easy to lose your discipline and try to win projects just to win them because that's what we do. That's the business that we're in. We don't do that and we haven't done that. We've remained disciplined about how we deploy capital in building out our network because we're building off of a really strong existing network, we're able to get very attractive returns on the capital that we deploy because we are building off of a network.
We don't have to build everything from scratch. So when we expand our TGP system, for example, we just completed a number
of expansions there. We're adding compression, maybe we're
doing a little bit of price for that move that is compensatory that is attractive to us in terms of the return on invested capital. So we've been operating and developing this backlog and adding to it as projects go into service using a 15% unlevered after tax hurdle rate as a starting point, okay? So when we have 10 year contracts as we do on Gulf Coast Express and PHP, we dial back off of that. Still get nice attractive double digit unlevered after tax returns, but a lot of that is because again we've got an existing network. In that case, we're going from a place where we've got a network in West Texas, interstate primarily, to a big network in the Gulf Coast.
We are able to continue to get very good returns in a highly competitive environment because we have a great network. And so here you see our backlog as it stands right now at $5,700,000,000 with 68% of that being in natural gas. So capturing this opportunity in natural gas and doing it at a 5.4x EBITDA multiple. So very good opportunities. It's a combination on the gas side of supply push from the Permian and the Bakken primarily in our case and then demand pull in LNG and Mexico exports.
Beyond the backlog, we think and you can look at our historical investment numbers, we think we'll find the opportunity to put to work $2,000,000,000 to $3,000,000,000 worth of capital in projects every year. I mean, that's very dependent upon opportunities and making the investment decisions in light of all the circumstances. But if you look at our track record, dollars 2,000,000,000 to $3,000,000,000 is a reasonably achievable run rate. And where might those things come from beyond the backlog? $800,000,000,000 worth of North American energy infrastructure investment is required to support the growth through 2,035.
Now will that be exactly how it continue to produce more crude, more natural gas and more NGLs than we need. We'll need the infrastructure to get those to market and to get those to the water. So for us, the 2 big boxes you see on there is market access for surging Permian production. We've got 2 the first two big takeaway projects gas projects out of the Permian are ours. And then also, we've been very successful in signing up the upstream capacity needs for the LNG export facility.
So those are 2 big ones. But there are others take away from Arcellus Utica storage to support renewable generation, etcetera. So a number of opportunities for us to continue to get to that $2,000,000,000 to $3,000,000,000 a year of new projects each year. All right, 501 gs, so the headwind. So let me try to calibrate this for you.
We've talked about it before on the calls. So there are a number of things that mitigate the 501 gs risk for us. First, we have rate settlements on a number of our pipelines and those rate settlements include a moratorium on typically either party initiating either our customers or us initiating a rate change proceeding. So that protects us for a period of time. Then we also have many of our rates are negotiated rates.
We're not deploying the capital in our natural gas business, in our intrastate business at FERC returns, okay? We enter into arm's length transactions with our customers and we're able to negotiate a rate that our customers are fine with and we're fine with and that gives us the return that we need in order to deploy capital. We're not using a 10.55 FERC ROE when we make those decisions. So those rates are outside of the cost of service rate making process And that makes up a lot of our it makes up certainly a big chunk of our business for the new projects that we're investing capital in, but we also have them in a lot of our base business. And then finally, this is really a competitive market.
And again, without getting on too much of a digression here, that's the fundamental logical flaw in what the commission has done. Over the last 30 years, they created a competitive market. Our terms are set in meetings with our customers 1 on 1 where they get something they want, we get what we want, right? Not in hearing rooms in Washington, D. C.
That's the way it was done in the '70s '80s, okay? Over the last 30 years, a very competitive market has been built, and we think the commission should recognize that as it's exercising its discretion on its Section 5 authority. But here's the 3rd mitigating element. As a result of that competitive market, a lot of our rates are discounted. They're below our MAX rates.
And so if you think about what a change to our FERC regulated maximum rate on our firm transportation arrangements means it affects a little less than 30% of our interstate revenue. That's the part of our business that's undiscounted, that's not under negotiated rates, okay? So with the combination of the and the commission seems to be respecting those things, right? So the combination of the rate moratoria that we have in place and the negotiated rates and the discounted rates, meaning that a change in our maximum rate does not affect all of our interstate revenues, we think this will be mitigated and spread over time. Now, our approach has been proactive.
This is really a strategy that we have to undertake with each set of customers on each one of our regulated systems, right? Because it's a different particularly at the utility level, it's a different group of customers for each system and there's different history, etcetera, etcetera. So, our approach has been to work with our customers. We have 2 active discussions going on right now. One is on EP and G, the other is on TGP, and the commission has shown some flexibility on allowing us to work this out with our customers in those settings.
So all of that is what makes us confident in our previous remarks that we feel like that this is going to be mitigated and spread out over time. So that's how we're approaching this particular risk, and I think we'll do all right with it. Okay, ESG, so this is a new this is new for us. We, in response to shareholder resolutions, put together our first ESG report in 2018. And in it, we capture a lot of information on what we already do and there's a lot to that.
I mean, we, for example, our main impact, we're not a large producer, we're not a large consumer, so we don't create a lot of greenhouse gas emissions. Our big issue is methane emissions, natural gas. And so, for decades now, we've been working on controlling that because it's money to us. What we get to transport it is, depending on the rate, it's a tenth of what the stuff itself costs. We have a high economic incentive to keep the gas in our pipe, right?
And so we've been reducing and mitigating greenhouse gas emissions for decades now. So a lot of what we did was showing what we already do and how we manage the safety of our assets and the safety of our employees and the public contractors, etcetera, and then laying out what we're going to do from here. So, what additional reporting we're going to do from here. So just a couple of observations I'll make. This is important to many of our institutional investors.
We've gotten very good feedback. Been told that it's comprehensive, transparent and thoughtful. Our report provides a good example of improved sustainability disclosure. 1 of the rating groups said that for the oil and gas and chemical sector, it was the best report he had seen so far, which is all very encouraging. But the comment I liked the best was this.
There weren't a lot of pictures in there. There was not a lot of gloss. It was numbers. It was numbers just like our financial reporting. It was statements and numbers, right?
And that's how we do things. This was not a consultant heavy thing, not a lot of flash in there. It's really all meat, okay? And that's the way we're handling this effort. We're incorporating it into our operations.
It's part of what our operations groups do. And our objective is to do it in a way that tells people what we're already doing, do it cost effectively, which we're doing, not consultant heavy, and get something out of it. While we're out there measuring all the things that the rating agencies want us to measure, measure something that's meaningful to us. So, I think what we've done so far is consistent with all those principles and very consistent with the way we do things. Okay, more on overview on natural gas.
Dollars 5,100,000,000 of 2019 budgeted segment, EBITDA. We've got $3,900,000,000 of committed growth projects over the period. Permian takeaway, finishing our Elba Island LNG facility with potential for expansion of that down the road, transport projects supporting LNG, expansions of our gathering and processing network in the Bakken and in Mexico. Again, increasing utilization of our existing network and the opportunity to build out our network at attractive returns. All right.
So now a few of the opportunity sets here for natural gas, in particular, LNG. And again, how we participate in this is we provide the transport and we provide the storage to get the gas to the liquefaction facility. It's a business that we already do for every other customer that we do it for. So it's not a lot of additional risk for us. It's certainly not difficult for us to build or to operate.
We've already contracted 5.3 Bcf a day with an 18 year average term. So we're participating deeply in this business, but we're doing it in a way that's very consistent with the risks and reward profile that we want. And also you'd have to say pretty capital efficient. This is 5.3 Bcf contracted that were for $1,000,000,000 we're building that capacity. Again, an indication that we can build off of our network at very attractive returns.
And then you see the Elba Island liquefaction facility that we're building, dollars 1,200,000,000 to Kilometers share. Another growth driver, the Permian production. So we have 2 takeaway projects secured, Gulf Coast Express and Permian Highway. I'll talk about each of those. And if you believe the projections here, it's close to or it's about one of those pipelines every year going forward to deal with the associated gas that's coming out of the Permian Basin.
So we are able to take advantage of this with our existing network. EP and G has done very well selling its capacity out of the Permian as people are looking for any way to get out of the Permian. We have the new build opportunities and we'll get additional value on from our Texas intrastate systems. So this is a very good story and a very good place for us on our existing assets and more growth to come. And a very interesting driver here because it's oil driven.
It's driven by the investment in the oil. It's not really driven by the natural gas value. Obviously, the producers want to get something for their natural gas, but they mostly need to get rid of it. They need to move it to a place where there's a market. That's allowed us to secure long term commitments for our pipeline projects.
And here's the first example. Gulf Coast Express, 2 Bcf a day pipeline, dollars 1,750,000,000 overall investment in that pipeline and 10 year contracts, 10 year contracts secured with Creditworthy shippers. October 2019 in service, we're on track for that. We're doing well on this project. And this is again everybody values our infrastructure more than the also our customers want to participate in these projects.
Okay. Permian Highway pipeline, another 2 Bcf a day. We've identified a little bit of expansion capability by upsizing the compression, adds 100 a day that we're out marketing right now, dollars 2,100,000,000 of capital in service in October of 2020, again, 10 year contracts. And this is a bit unprecedented. And I think consistent with what we've seen in the overall growth of gas supply and demand, we FID'd GCX in late 2017.
And just within a matter of months, we had the 2nd pipeline, PHP, FID'd as well. So a lot of growth in the Permian and a need for infrastructure to get it out. And again, what's happening with that gas is it's coming to what we think is the best intrastate system in the state of Texas. And over when it gets there, it can go to industrial markets, it'll go to power markets that are attached, distribution, the LNG facilities, of course, but also to Mexico, where again we participate, but we largely do it from the comfort of the United States. So we export off of Arizona, West Texas and also in South Texas.
We have a significant share, a little less than 70% of the overall market there. This market, we believe, is going to continue to grow. It's grown dramatically over time due to a combination of factors. 1 is growing demand for natural gas, particularly in the power sector second, declining domestic production in Mexico and third, LNG imports, which ought to be replaced or displaced with North America or with U. S.
Natural gas. So all those factors have led to continuing growth in this market and our ability to serve it both with our transport, sales gas off of our Texas intrastate system and storage services, again, all while participating mostly from the United States. We have one pipeline into Mexico, our moderate pipeline, and that's been a very successful investment. So, a good market for us, one that we've participated in and expect to continue to participate in. Now moving to some into the other segments, products pipeline, we've got a 9,500 mile network, 2,300,000 barrels a day, EBITDA segment EBITDA of $1,300,000,000 relatively small portion of the backlog attributable to this asset, very cash flow efficient, high free cash flow for us, good stable assets, fee based, not subject to commodity price, cheapest way to from A to B, so strong positions across our network there.
On Refined Products itself, domestic growth about 1.1 percent a year. Now we are seeing slightly higher growth rate than that. We also get the benefit on the FERC regulated pipes of indexing, which gives us predictable margin growth 4.4% expected increase for 2019. Terminals, so we've evolved this business, John and his team have evolved this business over time. We have gotten out of some of our bulk terminal businesses and focused instead on that were mainly labor plays.
You come in, you load stuff, store stuff and you get paid, and it's all about what your labor cost is. We've divested a lot of those and we focused our attention really on 2 things. 1 is on the liquids part of the business and primarily refined products there where we have great positions and secondly more on our hubs because we're looking for in this business a very simple business, you put stuff in tanks, you store it, you take it out. We want to make sure we're getting more than storage. We provide ancillary services, we provide multimodal capability and the opportunity for people to blend, etcetera.
So we built this business around the hubs, our hub positions and liquids primarily, dollars 1,200,000,000 of EBITDA, again, relatively small call on capital in this business. And here you see the breakdown. Our hub terminals make up 49% of our segment EBITDA here, market terminals, which are specific to serving specific geographic refined product demand, our Jones Act tankers, where we have a good position, efficient new vessels that make up a pretty good share of that particular class of vessels and we've kept them on the water, meaning we've kept them leased out, that's 16% and then other logistical services like what we do for Nucor, etcetera, 12%. So what we're trying to provide in this business is something that gets us more value. It's more than storage and more than just a contango play.
It's about providing value added ancillary services. Overall, strong liquids fundamentals, it's not the same growth obviously as what we're looking at for natural gas, but there is growth and the growthy part of it really is in exports because we are a net exporter of refined products have been since 2012 or so and our terminals group has a great position on the Houston Ship Channel that enables us to participate in that. So we built out 11 docks. We've got the capability to move. We've been moving north of 300,000.
It's down a little bit in just like the current month, but we've been moving over 300,000 barrels a day across our docks, refined products to meet world demand, which is growing faster than North American demand. And here's an example of one of those hub positions. This is our Houston Ship Channel position, 43,000,000 barrels of total capacity and primarily refined products capacity. We handle 15% of the exports, which I was just referring to. We have 20 inbound pipelines, 15 outbound pipelines.
We've got bargeaux, ship docks, truck racks and train facilities, but also 14 cross channel pipelines. So what we've done over the years is interconnect our facility so that we can provide even more flexibility, more options to our customers, which allows us to extract a higher value than what you would get for just having a crude tank, for example. We've invested about $2,000,000,000 nearly $2,000,000,000 in this hub since 2010. Look, there's competition here. Our customers are getting into this business, so they're building refined products excuse me, we're building they're building refined products terminals on the Houston Ship Channel.
So we've got competition, but we think the flexibility that we we know that the flexibility that we offer, the optionality that we offer at our facility with all of the connectivity inbound and outbound and within our facilities is a superior offering. And so, we believe we'll win out in the marketplace. CO2, so you see the summary of our CO2 our pipeline, our CO2 resources and our oil fields, this amounts to $850,000,000 of segment EBITDA. And this business, there's some oil that can only be recovered and can be recovered quite economically even in today's price environment, only be recovered with CO2. We have it.
We also have a very talented and experienced EOR team. That's another rarity. That combination makes us very happy to be in this business because it produces returns like this, all right? So we have on the left the IRR over the 2000 to 2018 period in our oil and gas business 18%. When you combine it with our source and transportation, the CO2 source and the pipeline transportation, it goes to 28%.
And it has allowed us to accumulate cash flow over the period including during the commodity price downturn period, dollars 6,200,000,000 when you get when you look all the way through 2019 budgeted period. So CO2, a niche business for us. Some of it looks a lot like our other businesses. We've got pipes here. They're a significant part of this business.
We've got pipelines. We operate pipelines with other commodities. We operate them for 3rd parties as well as for our own use in our enhanced oil recovery fields. We have the CO2. We got the people that can turn that CO2 into oil and do so at attractive returns and pile up the cash.
So a lot of people looking to be cash flow positive in that particular sector. We're accumulating free cash flow in this business. And so there's no there's been a lot written up here, there's no blockbuster announcement on CO2. We like this business, We make good returns in it. We have it is a niche business, but we're happy to be in it because of the returns that it produces for us.
But we are a shareholder driven company. And as we've said many times, if somebody wants to show up with the money and we'll make an attractive proposal that will allow us to comfortably determine that our share price will be higher at the other end of that transaction, that's how we act, that's how we think. We think, deliberate, decide and act like owners. That's what we'll do. But because we behave that way, if anybody thinks they can just drop a rumor out on Bloomberg and that that's going to somehow pressure us to do something, they don't understand how we operate.
So there's no blockbuster announcement today. We still feel the same way about this business that we felt for a long time. Last point on CO2, big fields get bigger. And so on the right, you see we've been wrong about Sacrock for years. I always say there's this big drop off coming and it's coming soon and we've been wrong delightfully so every time.
We keep pushing out we keep pushing it out and we're pushing it out again. On Sacrock, we've been not just evaluating, but exploiting the transition zone, which adds another 700,000,000 barrels of original oil in place. We're up to, Jesse, I think 3 projects now that have extracted from the transition zone, and there's more to come there. So we've got 2,800,000,000 barrels of original oil in place, another 700, that are targeted in the transition zone. Yates, the Yates field has 5,000,000,000 barrels of original oil in place.
As we get smarter and as we get more experienced, we're going to find ways to get more and more barrels out of these big fields and we've got a track record of doing so. So that concludes the segments, and that concludes my presentation. So I'll turn it over to Kim.
Well, good morning, everyone. The good news is you only have to listen to my voice. For 15 slides. David is going to do the budget this year. So starting on the first slide, I think I want to reemphasize a point that Rich made in his presentation and that is that we generate significant distributable cash flow in excess of our dividends.
So if you look at the last 3 years, 2016, 2017, and 2018, we've generated approximately $10,000,000,000 in excess of our dividend. And that has we've taken that $10,000,000,000 and we have 100% internally financed our expansion CapEx. And to some extent, we've used that cash flow to pay down debt. And as a result, if you look on the right hand side of the screen, our debt to EBITDA is down from 5.3 times to 4.4.5 times at the end of last year. And we have not issued any equity in the last 3 years and don't plan to GAAP metric, and this isn't totally apples to apples, but if you look at cash flow from operations on our GAAP cash flow statement for the last 3 years and you subtract off the dividends that we paid, then we have generated cash flow from operations of approximately $10,500,000,000 in excess of the dividends that we've paid.
And so in 2019, as Rich said, we expect to generate $2,700,000,000 in excess of what we're going to pay in dividends. And that just gives us enormous flexibility in terms of generating value for our shareholders. So we generate a lot of cash flow. It's also very stable cash flow. If you look, about 96% of our 2019 budgeted segment earnings before DD and A is either take or pay, fee based or hedged.
Looking at that breakdown, we've got 66% of our cash flow, which is about $5,500,000,000 that is take or pay. When it's take or pay, that means that people pay for the service even if they don't use it. So when you think about revenues being price times volume, there's no price risk, there's no volume risk on those cash flows. About 25% is fee based. What that means is the price is set, but we also have volume risk.
We have volume risk. So but you have to look really at the underlying business to understand what that volume risk looks like. On 10%, this is coming from our products pipelines. Products pipeline or product petroleum product demand is very stable in the United States. We are moving petroleum products from refineries to demand centers.
And if you look at that demand from 2011 to 2019, and Steve showed you this in your slide, both for our pipelines and for the U. S. As a whole, that demand has grown. For our pipelines, that's grown at about 1.4% per year. So very stable petroleum product demand.
On the natural gas side, that's about 10% of our other fee based cash flow. On the natural gas side, this is largely coming from our gathering assets, an economically viable acreage, where we have producer dedications. This is in the Bakken, in the Haynesville, in the Eagle Ford. That's where what's generating that cash flow. And then about 5% of it comes from our terminal segment.
And in our terminal segment, about 86% of that cash flow of this 5%, it comes from our high utilization liquids terminals. And what that is, is ancillary charges. So when people are in our terminal, if we're going to load a ship, then we get some ancillary charges for loading that ship or if they're going to blend their product. So it is it's revenues that are not take or pay but are associated with high utilization terminals. And then also on the bulk side, it's associated with requirements contracts on pet, coke and steel.
So if our customers in the pet, coke and steel business are going to move product, then they are required to move it through our terminal. So even though the volume here is not guaranteed, these cash flows are underpinned by assets which generate very stable volumes. Now if you look at the 5% that's hedged, here if we didn't hedge it, you'd have both price and volume risk. But on the price side, we're hedging it to take away that risk in the near term. On the volume side, if you look at it, most of the volumes in this 5% are associated with CO2.
And if you look at our volumes in the CO2 segment, we have come in within 1.4% of our budget over the last 11 years. So we are able to call our shots with respect to the volumes in our CO2 business, the oil volumes in our CO2 business. And then lastly, we've got about 4% that is commodity based. And this is the source of our crude oil. So just to give you the breakdown of this cash flow by segment on the next slide, You can see the natural gas segment, we've got 80% take or pay.
And then in the terminal segment, we've got 71% take or pay. So those two segments have a huge proportion of take or pay contracts. On the product segment, you've got 28% take or pay. But as we discussed on the other fee base, a large portion of that is associated with petroleum products, which have a very stable and growing history. And then if you look at the CO2 segment, I think something that is not well understood is in the CO2 segment, understood is in the CO2 segment, 30% of that segment has take or pay contracts.
And that's really on our S and T business when we're moving the CO2 from Southwest Colorado down into the Permian Basin. So that gives you a sense for our secure cash flows. We also have very high quality diversified customer base. If you look, our average customer represents 0.1% of our 2019 net budgeted revenue. So we got a lot of customers.
Now we do have some concentration of those customers. If you look at the top 25 customers, we expect that they will generate approximately 48% of our 2019 budgeted net revenue. If you look at how their rating their credit rating breaks down among those 25 customers, over 90% is BBB or better or post significant credit support. If you go a step further and go beyond our top 25 customers to any customers that we expect to generate greater than $5,000,000,000 I mean $5,000,000 in 2019 budgeted net revenue, that's 238 customers. Okay, so those 238 customers we have, which collectively represent about 87% of KMI's 2019 budgeted revenue.
There we only have 5% of the customers that have a B- or lower rating. Take it a step further and we look at 100 percent of our revenue and look at how that breaks down among classify our customers by what type of customer they are in terms of in 69% of them are end users like LDCs, chemical companies and refineries, okay? So very strong customer base. Now let me make one but I think for some of you who aren't there, it's worth reiterating. PG and E last week on our earnings call, But I think for some of you who aren't there, it's worth reiterating.
PG and E is a customer on our Ruby pipeline. As many of you know most of you know, they've announced that they intend to file bankruptcy. But we have we're cautiously optimistic about the contracts that they hold on Ruby. And that is because they have they utilize these contracts. These are contracts that are core to their gas and electric business.
These contracts were approved at the time that they entered into them by the CPUC. The CPUC requires them to hold long term firm transport capacity. Our Ruby pipeline provides them some reliability and diversity of supply. Earlier this year, we saw an outage upstream of GTN, which is a competitive pipe to Ruby. And so they were still able to get supply into the state because of their position or because of the contracts that they hold on Ruby.
So it provides them reliability and diversity. And it's our understanding that in the prior PG and E bankruptcy that they did not reject any of the any of their long term firm transport contracts. So, for that reason, as we said, we are cautiously optimistic about the outcome there. On the next slide, invest going forward? How much CapEx can we invest?
And this slide is and we tell people between $2,000,000,000 $3,000,000,000 per year. And this slide is part of what gives us confidence that we can do that. So if you look at the last 11 years, 2008 to 2018, we've invested $2,500,000,000 per year on average, okay? On the right hand side of the slide, you can see what we have invested over the life of Kinder Morgan. We've invested almost a little over $61,000,000,000 about 54% of that is expansions and contributions to JVs and then about 46% of that is in acquisitions.
And then on the bottom chart on the right hand side of the page, you can see the total invested by segment. About 58% of that investment has come in the natural gas segment. Now you can also see that Canada has a negative investment, okay? And the reason that is, is that these numbers net out divestitures. And so when we sell assets for more than the cash that we invested in them, then you have a negative investment.
Alternatively, we've sold assets previously for less than we have invested in it. The most the example of that would be REX When we bought El Paso and we were mandated to make sales of assets by the FTC, we sold REX for less than we had invested in it. We continue to show that leftover, if you will, in our Invested by in our total Invested by segment. And the reason we do this is to help you that's the methodology that we use. And when I go to a minute to returns on invested capital, that's how we calculate our returns on invested capital because we are really trying to show in return on invested capital a true cash picture.
If we got back more cash than we invested, then we show that benefit. If we didn't get back as much cash as we invested, then we burden ourselves with that. So on return on invested capital, we have averaged our return on invested capital has ranged between about 10% 15% since 2008 and you can see that on the red line on the lower graph. Now we've been tracking our returns on investment since 2000. If you go back to 2000, the return on invested capital was in the same range, between 10% 15%.
Currently, we're at the low end of that range, and you can see that, that as a result are largely a result of commodity pricing and the impact on our CO2 segment, okay. Between 2014 2017, our average weighted realized price on our crude sales or oil sales in the CO2 segment was down by $30 per barrel, okay? And so that is a large driver of the change on our return on investment. Now over the last 5 years, we've averaged about 10%. In 2018, we our average return on invested capital was 9.5%, which was essentially flat to 2017.
At 9.5%, we're still earning in excess of any calculation that I've seen on a cost of capital. And on new projects, we're targeting well in excess of this. We're targeting it, as Steve said, roughly 15% return on investment. You can see on the black line on the lower chart, return on equity. And you see that has come down for two reasons.
1 is return on investment has, but also because we are 100 percent equity financing our expansion CapEx. And so we are burdening the denominator in this calculation with all of the CapEx that we are spending. And so that is impacting return on equity and you can see that on the shaded portion of your slide. So as our returns on invested capital have come down, investors have asked us, are you really earning what you think you're earning, on the investments that you're making? And the answer to that question is that we are earning the return that we expected.
We're actually doing a little bit better than what we expected. But there are other things that are offsetting that. So hopefully, the next two slides will help you to understand that. So starting first with our project performance, and these are projects that we completed between 2015 2018 and it's the projects in natural gas products and terminals. So when we went to the Board to get approval for these projects, we originally estimated that we would achieve a 6.1x build multiple.
And that is just the CapEx that we expected to spend divided by the year 2 EBITDA. If we look at those projects, now that they are complete, what we've actually achieved is a 5.9 times, okay? That's on our overall portfolio of those projects completed between 2015 2018. Now if you just want to isolate natural gas since natural gas is about almost 70% of the current backlog. On natural gas, what we got approved by the Board was a 5.8x multiple, and what we've actually achieved is a 5.2 times multiple.
So on our expansion projects, we have done better than what we originally anticipated, okay? So where is the offset? This on this slide, let me we're going to take you through I'm going to take you through the change between 2014 EBITDA and the 2019 budgeted EBITDA. So 2014 was $7,400,000,000 The change in crude price between 2014 2017 is about a $600,000,000 reduction in EBITDA, okay? And that is we had the weighted realized weighted average price for us on our oil sales in 2014 was $88.41 You can find that in our 10 ks if you're interested.
Our weighted average oil price in 2017 was $58.40 So a $30 change in oil price is what's driving that $600,000,000 Then, there's about $500,000,000 associated with asset divestitures. The 2 biggest ones, TMX or Trans Mountain and half of Southern Natural Gas, okay? Now we use the proceeds from those divestitures to help pay down debt, okay? And so that is part of what helped fund the 8 point $3,000,000,000 reduction in net debt since the Q3 of 2015. If you look at our midstream assets, our gathering and processing between 2014 2017, if you look price and volume resulted in about a $300,000,000 reduction in those assets.
Now since that time, that's come back a little bit, but that's shown in the other category. And then we had coal we had most of our coal customers declared bankruptcy. And so that's about 100,000,000 dollars We had about $200,000,000 benefit from other items and then the EBITDA from our expansion projects between 2014 to 2019 budget is about a contribution of $1,700,000,000 So if you look at our EBITDA in each year from 2014 to 2018, We've consistently generated over $7,000,000,000 in EBITDA in every year. And if you look, we've grown that EBITDA from 'fourteen to 'eighteen by about $400,000,000 despite multiple market disruptions and significant strategic efforts, including asset sales and debt reduction. Steve talked about this a little bit, but because we spend most of our time when we're talking to investors focused on underlying fundamentals, focused on financial performance, focused on our strategic outlook.
And I think that is all very, very appropriate. I think the discipline with which we approach the business, and that is core to our culture is not well known or appreciated. So on a weekly basis, we update our financial forecast. So every week, we know where we stand for the full year versus our budget and versus the prior week. Every month, we go through every outstanding account receivable in the company.
And I can tell you this is not my favorite meeting. Why hasn't a customer paid? When are they going to pay? Do we need to draw on credit support? Do we need to send a demand letter?
Do we need to initiate litigation? We are on top of that on a monthly basis. At the end of every month when we close the accounting books, we compare how do we do on the actual versus our last forecast. And we're consistently trying to get those numbers closer and improve our financial forecasting ability. We report we're one of the first companies in our space to report earnings and that's we want to close the quarter and move on and continue to look forward.
We don't want to be still looking backwards at the last quarter, a month or 6 weeks after the quarter's open. With our segments on a quarterly basis, we sit down and go through what we call a quarterly business review. And this is really to look out longer And then twice a year, we do a much longer term outlook on our business opportunities and threats. So the way we accomplish these is through a set of regularly scheduled meetings. So on Monday, every Monday from 1 to 3, except for 2 Mondays a year, that's the July 4 the week of July 4 and the week of New Year's, we generally don't meet.
But every other Monday from 1 to 3, we are in there going through our financial results and updates with our business units. These meetings are scheduled a year in advance, okay? So all our meetings, so roughly 50% of our time is scheduled a year in advance. And as a result of that, there's a lot of accountability. We get a lot of real time information.
And that allows us to react quickly to things, to make informed decisions, to identify potential opportunities and to address potential risk. So we have a saying at Kinder Morgan that problems aren't like a fine wine, they don't get better with time. So we try to get on top of those things quickly. Let me spend a few minutes talking about how we think about allocating capital between the balance sheet, the dividend, capital projects and share repurchase, okay? On the balance sheet, as we've said, we have achieved our 4.5x net debt to adjusted EBITDA.
On the dividend, we've set our dividend target for 2019 at $1 for 20.20 at $1.25 per share. So we don't have any near term decisions to make on the dividend. So really, it gets down to how much do you allocate to capital projects versus how much do you allocate to share repurchase. On our capital projects, we're generally targeting around a 15% unlevered after tax return as Steve took you through. Now if you take that 15% unlevered after tax and you lever it on a generic project gives you somewhere between 25% to on a generic project gives you somewhere between 25% to 30% levered after tax return.
If we look at share repurchase, share repurchase opportunities are going to be depending on if you assume any multiple expansion somewhere less than 20%. And how much less depends on how much multiple expansion if any that you assume on those share repurchases. So we don't think that these two opportunities have to be or should be equivalent. We think that a project needs to earn a higher return than share repurchase because share repurchase, we're buying equity and a diversified set of cash flows. Project is a single asset, so it has more risk.
So you need to earn a higher return on those capital projects. But we think at this time, the difference is sufficient enough that we are allocating our free cash flow to capital projects. And then to the extent that we have some left over, we are repurchasing shares, okay? Now we continually reevaluate this, okay? As things change, we're going to continually reevaluate that.
But I think that this creates a healthy tension as well to make sure that we are not kidding ourselves when we are investing in capital projects. We spend a lot of time making sure that those capital projects earn the returns that we expected them to earn because we have this other alternative, okay? And we also try to be conservative when we underwrite those capital projects. And so a lot of times when we're looking at the terminal value and we're saying, okay, where are we going to be able to renew these contracts when the 10 year contracts roll off? We're going to take a big haircut and running those returns.
So we are because this share repurchase opportunity is there, that creates accountability and that creates discipline. So, just very quickly, on the difference between distributable cash flow and net income, and you'll see this in the calculation when David goes through the numbers. There are 2 primary differences. The first is DD and A versus sustaining CapEx. We add that DD and A, we subtract sustaining CapEx.
DD and A is a number that our accountants determine. Sustaining CapEx is a number that our operations department builds from the bottoms up. And it is based on need. It's based on long term plans. It's based on regulatory requirements.
And it's based on risk analysis. So two concerns that I hear people verbalize about replacing the DD and A with sustaining CapEx. One is, well, you just must not be spending enough. And that's why you're sustaining CapEx is significantly different than your DD and A. And so what I would point you to there is our safety record, okay?
If we were not spending sufficient dollars on these assets that would show up in our safety record. We have been publishing on our website since 2007 our safety record. And we compare and it's in depending on which year you're looking at, I mean there's roughly 30 different metrics. And we compare those metrics to the industry average. And we are generally better than the industry average.
So we've got a very strong safety record. The second concern I hear people verbalize is, oh, this will reverse over time. At some point this will change. So we've shown you 10 years of history here where it has held true. And there's not enough room on the slide, but if we went back ten years more to the inception of Kinder Morgan, it would still be true.
So over 20 years, this has not changed. The second adjustment that we make is we add back book taxes and subtract cash taxes. Now cash taxes can vary year to year. And you look in 2012, we actually paid more cash taxes than we had book taxes. But recently, we have not had significant cash taxes and we do not expect to be a significant cash taxpayer until beyond 2026.
So, Rich took you through where KMI trades versus the S and P. And most of you know that it's at one of its low, it's about 5%, one of the lowest percentage it's been in a very, very long time and well below the long term average. If you look at KMI versus the average midstream company, we trade at a discount whether you look at that on a DCF multiple or whether you look at that on an EBITDA multiple. So if we trade it at the average, there would be about 20% to 30% upside in KMI's price. So just to sum it up on the final slide, We think KMI represents a very compelling investment opportunity.
We've got 90% take or pay or fee based earnings. We expect to generate in 2019 $7,800,000,000 in adjusted EBITDA, $5,000,000,000 in distributable cash flow. We're growing our dividend by 25%. We've got a mid BBB credit rating. We've got a highly aligned management team.
We're very disciplined in the way that we approach our business and in our capital allocation. And we've got an active stock buyback program. And as one of our Board members likes to tell us, market sentiment may change but we're just going to continue to focus on making money for our shareholders. And that's it. And I think we'll have a break now.
And then we'll come back with David Michaels.
Okay. Hello? All right. If everyone could please take your seat, we'll go ahead and get started. All right.
Well, I'll go ahead and get kicked off. Kim left off by saying that, despite or regardless of how market sentiment changes, we're going to be focused on making money for our shareholders. And so I think that's a good segue into just how much money we're going to be making. So as Steve mentioned, I'll be going through this riveting presentation of our 2019 budget, and this is going to be consistent with the high level guidance that we presented in December, just in a lot more detail. And as usual, we're going to be presenting we're going to be posting this presentation to our website.
We're going to have it up there consistently throughout the year, so you guys can come back and look at it and compare how we've actually performed to what we are budgeting. And I'll also be providing an update to that on our quarterly calls. So on the summary page here, the 2019 guidance highlights, we expect strong growth from 2018, dollars 7,800,000,000 of adjusted EBITDA, just over $5,000,000,000 of DCF, EBITDA growth from 2018 of 3%, DCF growth from 2018 of 6%, and our DCF per share of $2.20 up 4% from 2018. We expect to declare dividends of $1 per share as you're all aware of and that's 25% up from 2018 and 2018 as a reminder was up 60% from 2017. So it's worth noting that all of these growth rates from 2018 are on top of a very strong year in 2018.
During 2018, we grew our DCF and EBITDA by 4% 6%, respectively. And so these growth rates are on top of that very strong year. It's also important to note that during the year we sold Trans Mountain. So these growth rates are also on top of the fact that we sold an asset that was contributing about $200,000,000 annually to our EBITDA. We expect to spend during the year $3,100,000,000 in growth capital and contributions to our joint ventures and expect to end the year with a net debt to adjusted EBITDA ratio of 4.5x.
And as has been the case since 2015, we have no need to the equity or debt markets and we use our cash flow to fund to fully fund our dividend and to fund nearly 90% of our growth capital needs during the year. So going to our assumptions page, as you can see, the Natural Gas segment is the largest contributor to our growth in 2019 as we budgeted. And here you can see some
of the
key contributors to the segment. I think the key takeaway here is that we're seeing very favorable trends across numerous areas in the segment. We've got multiple expansion projects contributing to the growth, Elba liquefaction, TGP Tennessee Gas has numerous projects that have come online and are coming online. We expect increased volumes from the Haynesville and from the Permian to benefit EP and G and Kinderhook. Kinder Morgan Louisiana is also benefiting from a recent LNG supply contract going into service and those are partially offset by a lower contribution from GLNG due to an arbitration ruling calling for a contract termination.
Products is up 2%, so steady growth there, driven by our FERC index escalator, higher volume expectations on Highland Crude assets and through our splitter facility and those are partially offset by lower contracted rates on our KMCC asset. Terminals, pretty flat, down 1%. That segment has a negative impact due to a Edmonton tank lease expense that hits the segment post the sale of Trans Mountain. Other than that, the segment would be up a couple of percentage points year over year and that would be and that growth is driven by contributions from rate escalations and expansion projects primarily from the full year contribution from our baseline terminal project in Edmonton. Our CO2 segment is down 7 and that's almost entirely due to expected lower realized prices, partially offset by S and T volumes, which we project to be up 10%.
Our net oil production is expected to be about flat with 2018. Net oil volumes are budgeted to be less than 0.5 percent from the 2018 volumes with tall cotton volumes increasing year over year offsetting almost completely lower volumes at Sacrock, Gates, Katz and Goldsmith. The unhedged WTI price, which you can see there at $60 per barrel, is pretty close to our realized price for the full year 2018 of $58 per barrel. So the main driver of the $7.08 per barrel lower oil price to be realized in 2019 is a full year impact from the lower Midland to Cushing spread. We largely have that hedged for 2019 and that's at a negative $8 per barrel or a little bit north of a little bit south of $8 per barrel hedged.
Kilometers Canada is no longer on the slide, and that's of course, we sold Trans Mountain and Trans Mountain was the only asset in that segment. So that segment will no longer be receiving any contributions. The other Canadian assets that we have that Dax will touch on in his presentation of KML are reported in our other segments. And that's how they have been reported in the past as well. Interest expense is expected to be unfavorable in 2019 versus 2018 and that's primarily due to higher short term interest rates.
There you can see our LIBOR, 3 month LIBOR average estimate is 3.04%. That was consistent with the LIBOR curve at the time of our budgeting and that's relative to a 2018 average of 2.28%. Cash taxes, once again KMI does not expect to be a cash tax payer for U. S. Federal income taxes.
So moving on to our EBDA slide. Segment EBDA is up $321,000,000 and again, natural gas is the largest growth behind that. Multiple areas, as we discussed in the prior page, offset by CO2 in Kinder Morgan Canada and the sale of Trans Mountain. G and A is budgeted to be higher by $27,000,000 and that's largely annual merit increases and higher budgeted health and welfare costs. Interest expense is unfavorable $31,000,000 and that's due to the higher budgeted short term interest rates we talked about.
Non controlling interest, going down a few lines, non controlling interests are $23,000,000 higher and that's largely due to our partners share of the Elba liquefaction facility budgeted to come on line in February. And the larger NCI share is partially offset by lower non controlling interest from Trans Mountain as a result of the sale. You can also see the preferred stock dividends here going away in 2019. We paid $128,000,000 on our mandatory convertible preferred stock in 2018 and those converted in October. So we'll no longer have those payments.
So adjusted earnings are up $270,000,000 or 14% from 2018 and our adjusted EPS, which reflects the greater shares from that mandatory conversion of our preferred stock, is projected to be $0.99 per share or $0.10 11% up from 2018. So good growth in 2019 projected. On Slide 60, we'll go through our adjusted EBITDA. Here you can see the 8,000,000,376,000,000 segment EBITDA we talked about on the prior page, which has the JV DD and A split out by segments so that you have that information for your modeling. Next, we'll walk from the segment EBITDA reconciliation down to adjusted EBITDA.
We add back JV book taxes that are deducted at our segment level segment excuse me, in our segment EBITDA levels and we remove the non controlling interests here and then deduct G and A expenses to arrive at the adjusted EBITDA. NCI is higher here by $46,000,000 and that's due to the Elba LNG facility coming online. We talked about it on the prior page, but you'll notice that the change here is different than the change on the prior page. That's because we fully consolidate KML from an EBITDA standpoint. So their NCI is not deducted here as it was on the prior page.
And the reason we fully consolidate KML in our EBITDA is to better align the EBITDA to our balance sheet, which fully consolidates KML's debt. So that way we're an apples to apples comparison, but we do proportionally consolidate KML in DCF and in earnings. So that gets us to EBITDA of $7,817,000,000 and that's a 3% increase from 2018, again, despite the full year impact from the sale of Trans Mountain. So moving on to Slide 61, our 2019 DCF. So as we discussed, the DCF budget is over $5,000,000,000 or $267,000,000 higher than 2018.
So 6% increase on the DCF number from 2018. And this page reconciles to net income down to DCF, but I'll provide the main moving pieces from 2018 to 2019, including some on this page and then some on the prior pages. So as we talked about the budgeted segment EBITDA drives the majority of the year over year increase of DCF with growth of $298,000,000 if you exclude the NCI. Preferred dividends, as we talked about, are down $128,000,000 Those are partially offset by higher sustaining CapEx of $63,000,000 shows up on this page, dollars 31,000,000 higher interest expense, dollars 30,000,000 higher contribution to our pension plan this year versus last and $29,000,000 of higher cash taxes. So that explains $273,000,000 of the $276,000,000 in DCF growth year over year.
And those are just the main moving pieces or a number of other items, but those are the largest. So going through some of the explanations on those items that I haven't already touched on. Cash taxes are higher and those are driven by cash taxes that we expect to pay at KML. So KML is expected to become a cash taxpayer in 2019 and is also expected to make a payment for 2018 deferred taxes in the year. So that's a growth in cash taxes year over year.
Our average shares outstanding are $2,278,000,000 and that's 50,000,000 shares higher than 2018 and that's as a result of the conversion of our preferred equity. DCF per share is budgeted to be $2.20 up 8% excuse me, dollars 0.08 or 4% from the $2.12 that we generated in 2018. And the $2.20 per share of DCF is a 2.2x coverage of our expected declared dividends per share of $1 per share in 2019 or coverage of over $2,700,000,000 of coverage over the TCF. Moving on to the cash tax calculation page, you can see here we expect to generate a taxable loss in 2019 of $2,000,000,000 and therefore do not have to do not expect to be a U. S.
Federal cash taxpayer in the year. And in fact, given our large deferred tax asset, we don't expect to pay material federal cash income taxes until beyond 2026. However, as you can see on that page, you can see we have $106,000,000 of total cash taxes that we expect to pay in the year and that's as a result of some of our taxable subsidiaries, Plantation, Citrus, NGPL and KML are also are all included in that taxable subsidiary category. And as we talked about before, KML is the driver of some of our year over year higher cash taxes. We also had some state tax refunds that we received in 2018 that we don't expect to reoccur in 2019.
So that also explains some of the year over year change in our cash taxes. Moving on to sustaining capital. Overall, our sustaining capital budget is expected to increase $63,000,000 from 2018. Natural gas is the largest piece of that change at $40,000,000 higher expected sustaining capital spend in that segment. That's largely driven by additional integrity projects, including projects to make some of our pipelines pickable, which will make future inspections more efficient.
Terminals is up $16,000,000 and that's largely due to additional dry dock time for some of our Jones Act tankers as well as additional API inspection time during the year. Our CO2 segment is up $13,000,000 and that's due to additional pipeline integrity work on our Cortez pipeline in that segment. Those increases are partially offset here as you can see by the Trans Mountain sale of $10,000,000 lower capital expenses. Moving on to our quarterly profile page. Our quarterly contributions are not evenly distributed and this has been the case for a very long time.
Every year, Kim used to remind you all that we typically have our highest contributions in the Q1 and the Q4 and our lower contributions in the second and third. So now I have the privilege of reminding you that our highest contributing quarter typically is the 4th quarter followed by our first and then our second and third. And that's driven by some seasonal demand, some winter higher winter demand on a number of our pipelines as well as some cash tax and other corporate payments that we make throughout the year typically in the second and the third. Moving on to discretionary capital, here you can see the detail behind our $3,100,000,000 budgeted for the year in growth capital and contributions to our joint ventures. As you can see, the largest area of spend is within our Natural Gas Pipeline segment.
No surprise given all of the comments we've been making about the segment. The largest projects in natural gas are Gulf Coast Express, our Permian Highway pipelines, both of our pipelines being built out of the Permian, our Roosevelt plant expansion and the remaining spend on elbow liquefaction expected to come on in the Q1. In addition, as you can see on the right hand side of the page, this year we expect to make contributions to our joint ventures of about $600,000,000 for maturing debt at our joint ventures. It's very unusual for us to make that level of contributions for debt that's maturing at our joint ventures. Typically, the majority of our debt that matures at those entity levels are refinanced at the entity.
The majority of this amount relates to MEP, FEP and Ruby, and those are some of our assets that have they're facing some headwinds from contract rollovers and so the cost to refinance at the entity level there would be high. So these contributions we think are appropriate. And again, it's very unusual and it's worth noting that after 2019 FEP and MEP will no longer have any entity level debt. In the products area where we have $168,000,000 expected to be spent, that's driven by well connections to facilitate growth volumes on Highland and other small projects, including some capital spend on our KMCC pipeline. Terminals, dollars 147,000,000 in the year.
This spending is primarily tank and pipeline expansion investments to expand services in our Houston Ship Channel. CO2, here you can see the S and T and EOR broken out. The S and T spend is driven by our McElmo Dome expansion projects, and our EOR spend is driven by Sacrock projects and tall cotton spend. In the CO2 segment, we reassess capital spending in that area as commodity prices fluctuates to ensure adequate returns. Moving on to our sources and uses for the year.
As has been the case for prior presentations of our sources and uses, this is just a high level view of what our sources and uses are expected to be for the year. It does not take into account projections for working capital changes and is therefore just a guideline. So it also doesn't include KML, because KML funds its own capital needs directly and Dax will take you through the sources and uses at that entity. Starting with the uses first, we talked about our dividend expectations of $1 per share, that's $2,278,000,000 Growth capital projects of $3,100,000,000 and debt maturities of $2,800,000,000 We also ended the year 2018 with $433,000,000 borrowed under our revolver. Under sources, talked about our DCF being just over $5,000,000,000 for the year.
We had cash proceeds, our share of those cash proceeds from the Trans Mountain sale at the end of the year of just under $2,000,000,000 and the difference here is our revolver and debt needs of $1,600,000,000 Just over $1,600,000,000 We have plenty of capacity to fund that on our revolver and we'll take a look at potentially terming that out throughout the course of the year, but that will be dependent on market conditions. I'd also note that the cash proceeds on hand at the end of the year were received in early January. We paid off the revolver borrowings and plan to use the majority of the remaining cash to pay down $1,300,000,000 of bonds that are coming due here in early February. Moving on to our leverage and liquidity slide. We ended 2018, as I mentioned, at 4.5x adjusted EBITDA to adjusted adjusted net debt to adjusted EBITDA and expected to end 2019 at the same level of 4.5x.
Our strength in balance sheet with lower leverage gives us we think a much more strong financial position, greater flexibility and cushion. And I think that was reflected by the recent upgrades by both Moody's and S and P. We think those recent upgrades will come clearly with some lower cost of capital, but just as important, we think having that higher rating and a better rating will give us greater certainty to access the debt the investment grade debt markets as we when we need them. As you can see on the bottom right of this slide, our long term debt maturities coming due. We have some pretty meaningful debt maturities between $2,200,000,000 $3,200,000,000 annually during the next 5 years, but expect to be able to manage those confidently with our liquidity that we have on hand, our $4,500,000,000 committed facility, along with our enhanced access to the investment grade market, particularly given that recent upgrade.
So now with that, I'll turn it over to Dax.
Thanks, David. For those of you I don't know, the first thing you'll notice is my lack of a distinctive Western Canadian accent. So I'd ask you to just use your imagination as I go through this to enhance the effect a little bit. Okay. I'm going to start with an overview of KML as a company and some of the fundamentals and then I'm going to move into the budget.
Generally speaking, KML owns a suite of stable fee based assets that are central and very important to the Western Canadian Energy Complex. They include the largest crude storage terminal in Alberta with about 12,000,000 barrels of storage capacity, the largest crude by rail terminal in North America, the Canadian portion of the Cochin pipeline, which delivers condensate for blending and the largest mineral concentrate export import facility in the West Coast of North America. And there's really no direct commodity exposure associated with these assets. Structurally, KML is publicly traded on the TSX, and it represents about a 30% interest in these assets, with KMI retaining the residual 70%. Over the next couple of slides, I'm going to hit some of the high points of the assets starting with the Edmonton assets.
The 3 main storage assets are the North forty, which is 2,100,000 barrels of 100 percent owned capacity on KML land the Edmonton South Terminal which is 5,000,000 barrels of capacity controlled through a 20 year lease with Trans Mountain from which KML derives all of the merchant gross margin and the recently commissioned BTT which is 4,800,000 barrels of capacity that we own 50% of with Keyera. The rail assets include the Edmonton South Rail Terminal, which is a fifty-fifty joint venture with Imperial that can do between 210,000 and 250,000 barrels a day of throughput. And the Edmonton the Alberta crude terminal, which is also a fifty-fifty joint venture with Keyera and it can do 35,000 to 40,000 barrels a day of throughput. Moving to the next page, we've got the Canadian portion of the Cochin pipeline, as I mentioned. The earnings on Cochin are underpinned by 85,000 barrels a day of take or pay contracts that go through 2024.
It's got 110 a day of design capacity, but with some constraints on the U. S. Side, its practical capacity is more like 95,000 barrels a day. But it can obviously accommodate some additional receipts at the border, similar to a deal we've got in place that I'll reference here in just a second. The most valuable thing about Cochin obviously is that it's pipe in the ground, cross border pipe in the ground, which as we all know is incredibly difficult to replicate.
The Vancouver Wharf Terminal is a bulk commodity marine terminal with 6,000,000 tons per year of bulk capacity. The majority of that capacity is under take or pay contracts with long term customers. We've got a $43,000,000 diesel export expansion project that's kicking off that's underpinned by 20 year take or pay contracts that will be in service of Q1 or 2021. Beyond that, we've got 15 acres of undeveloped land and other potential projects that we're working to develop further. Finally, we've got the jet fuel line that delivers jet fuel from a refinery in Burnaby to the Vancouver airport.
Now before I get into the number specifics, I want to just cover some fundamentals here on one slide, specifically related to the Edmonton assets. Overall, Western Canadian crude supply is projected to grow by almost 2 1,000,000 barrels a day from 20 17 to reach about 6,000,000 barrels a day by 20,200, 35 or 50 percent increase. To accommodate that growth, there has to be incremental egress capacity, ideally by pipeline, but potentially by rail as well. Along with that, you need incremental storage and staging capacity, which is where our assets come in. With the largest merchant storage position and the best connectivity and optionality, demand for these assets will only continue to increase as we get incremental egress capacity out of Western Canada.
Now on the other hand, and I'm not saying that we'll always make money no matter what, that we'll always win no matter what, but over time what we've seen with these assets, while there's been little to no incremental egress capacity coming online over the past several years is that our rates continue to go up. Is consistent with the fact that production continues to outpace egress capacity additions and putting aside the recent strength in WCS as a result of the production curtailments, the large WCS basis discount has persisted for finding a powerful economic incentive for crude storage and most importantly a need for optionality. So again, over time, we have seen these rates on these assets continue to trend higher. The bottom line is that our Edmonton crude assets have solid economic underpinnings and strategic underpinnings in the Western Canadian crude picture. With that, I'm going to move over to a high level overview of the numbers in the 2019 budget.
Our budget contemplates $213,000,000 of adjusted EBITDA, $109,000,000 of DCF resulting in $0.90 of DCF per share, a $0.65 dividend per share, dollars 32,000,000 of growth capital and all that goes into ending the year at 1.3 times debt to EBITDA taking into account 50% treatment of the prefs with little or no debt. A key assumption in the budget is an FX rate of 1.32 or 0.76 going the other way. A 0.1 move in the rate results in about 600,000 of DCF change. And incidentally, the largest piece, really the most substantial piece and only piece of significant FX exposure at KML now is on revenues associated with coaching because the tariff is denominated in U. S.
Dollars. We collect U. S. Dollars and we convert them into Canadian. Overall, we're showing a 12% increase in EBITDA from terminals led by a full year of the baseline expansion and an 8% increase in EBITDA from pipelines led by the FERC index, which is assumed to be 4.4%, as David mentioned.
From a business mix perspective, Edmonton Liquids Liquids position is just under half of the company, crude by rail is about 21%, pipelines are 17% and Vancouver wars is about 14%. Moving to the next page, I'm going to go through segment EBITDA before certain items. Looking at segment EBITDA, the terminal segment is up $22,000,000 from $184,000,000 to $206,000,000 or about 12 percent, dollars 20,000,000 or almost all that is baseline for a full year. There's an additional $3,000,000 from incremental grain volumes at Vancouver Wards. There's $1,300,000 from contract escalations in Edmonton and those are generally the default escalation provisions as opposed to there's only there's not much in the way of contract renewals there.
That's partially and then $700,000 from Shed 6 reactivation project, which is a small expansion project at Vancouver Wharf got. That's partially offset by $2,000,000 from higher labor costs. Pipeline EBITDA is up $3,000,000 from $39,000,000 to $42,000,000 or about 8%. The largest driver is the FERC indexing on coaching, which is about again 4.4%, which accounts for about $2,400,000 FX adds a benefit of about $1,000,000 a full year of a short term deal for deliveries at our MAX Bass terminal in along the border adds about $400,000 and that's partially offset by higher OpEx and property taxes. G and A, as you see, is effectively flat.
Gross G and A is actually up a couple of $1,000,000 associated with higher labor and benefits, but it's offset by a credit that sends dollars to sustaining capital as we're actually capitalizing more overhead. And you'll see that in a second when I talk about sustaining. That gets you to adjusted EBITDA, which is $213,000,000 up $24,000,000 from 180%, 113%. Interest is and 13%. Interest is effectively budgeted to be 0 as we don't have any debt outstanding.
The $1,000,000 you see is largely for commitment fees and a little bit of interest associated with some working capital draws and repays throughout the year. Book tax is effectively flat. We generally book in our statutory rate of approximately 27%. It's a bit higher in 2019 due to some disallowed overhead expense. That gets us to net income before certain items of $122,000,000 versus $135,000,000 in 2018.
Preferred dividends are flat and that drops us to adjusted earnings of $17,000,000 which is down $4,000,000 from the $21,000,000 in 2018, which leads us to adjusted earnings per share of $0.48 down $0.14 from $0.62 in 2018. I think the overall story here generally is, you've got a full year baseline that's offset by the interest income associated with the proceeds that we had from the Trans Mountain sale that we accumulated interest on before we actually paid the dividend. Moving to the next page, I'll talk about the DCF buildup, and I'm going to drop down to the first item that I didn't cover on the previous page, which is cash taxes, and those have gone from about $8,000,000 to $52,000,000 which David touched on. That's consistent with previous comments, again as David mentioned, is largely attributable to the fact that we're paying 2 years worth of cash taxes. That's 'eighteen and 'nineteen in 'nineteen because we weren't required to make installments in 'eighteen for 2018.
So the 2018 portion is about $17,000,000 the 'nineteen portion is about $35,000,000 of the total of 52, a little bit more on that in a second. Sustaining capital is up $3,000,000 from $19,000,000 to $22,000,000 or about 16%. That's really all in terminals and as a result of the higher capitalized overhead that I mentioned. We changed our policy, our method of allocating capitalizing overhead after the Trans Mountain sale slightly. So we've got a little bit of a change associated with that.
That gets you back to total DCF of 109,000,000 dollars Now you back off KMI's approximate 70 percent interest or $76,000,000 That gets you to $33,000,000 of DCF available to restricted voting stockholders. Assuming 36,000,000 restricted voting shares outstanding, that gets you to $0.90 of DCF per restricted voting share against an expected dividend of $0.65 and leaves you with just under $10,000,000 of excess coverage and reflects a payout ratio of about 72%. Here we've got a little more detail on the cash tax calculation. You start with segment EBITDA of $248,000,000 dollars you back off $35,000,000 of G and A, a small bit of interest and tax depreciation, you get taxable income of 129 You apply the statutory rate that I mentioned a minute ago when talking about book taxes and that gets you to the $35,000,000 for 2019 that I mentioned. You add the $17,000,000 in for 2018 and that gives you $52,000,000 This page has a little bit on CapEx as well as sources and uses.
Starting with the top left, you see the sustaining capital detail that I've already discussed, noting that pipelines are flat and terminals are up about $3,000,000 Moving to the top right and expansion capital, total expansion is budgeted at $32,000,000 versus $42,000,000 that we actually spent in 2018. That includes about $5,000,000 for the remainder of baseline, about $20,000,000 for the diesel export facility and about $7,000,000 for the Shed 6 reactivation project, which is the small expansion project that I mentioned at Vancouver Wharf. The $10,000,000 credit you see on Cochin in 2018 stems from a situation where we determined that KML had spent some capital on behalf of KMI back in 2017. And this was basically KMI when we discovered that KMI reimbursed KML for the CapEx and that's what this is. Moving to the bottom of the page, we see on the left our sources of cash, which is essentially DCF and the uses on the right, which are expansion capital and dividends.
So you see that the budget basically contemplates that we'll fully fund expansion capital and distribute the rest to common shareholders with really no need to access any outside capital. Moving to leverage and liquidity, I'm going to start in reverse order at the bottom. You see that we have got the $500,000,000 credit facility with a 2022 maturity in place against the zero again with a zero balance. We had at year end $11,000,000 of letters of credit outstanding, but about $8,000,000 of that was actually in favor was for the benefit of Trans Mountain. Of course, we've got a reverse backstop in place in favor from them in favor of us.
This is just allowing them to get letters of credit up and running on their end. And as they get them up, we wind ours down. But again, we're fully backstopped with that. Moving to the top, you see our calculation of debt to EBITDA at year end. We're showing year end balance of $5,000,000 on the revolver.
And again, that's again for working capital purposes with some draws and repayments throughout the year. You add in the press at 50% of par, dollars 275,000,000 against EBITDA, dollars 213,000,000 you get to the 1.3 times debt to EBITDA coverage. I think the overall message here is that we've got a best in class very conservatively capitalized entity with a lot of borrowing capacity that we could use to pursue attractive opportunities if we so choose. Obviously, we need to see where the strategic review ends up, but using KML's balance sheet to grow is a very certainly
a very viable option.
Finally, as a concluding slide, I want to just walk through some of the opportunities and risks of KML. On the opportunity side, we've got rate improvements on re contracting. As I mentioned, over time, I think, obviously, the timing of incremental egress capacity out of Western Canada is difficult to predict. But as I mentioned, over time, throughout our history with this business, that John and his team have built since roughly 2,008, we've seen rates increase over time and we've been able to increase rates as these are really assets that are key to the Western Canadian Crude Complex. There's incremental rail business associated with some of those same pipeline constraints with the assets that we have.
And there is a potential for additional crude storage projects such as Baseline 2, which is a project that John's team is starting to look at and additional potential additional expansion projects at Vancouver Wars as we've talked about over time. On the risk side, we've got the Edmonton South rail terminal contract reset and that's not something that's not as much as a risk as what I would say is more of a known thing that's part of the original deal that we negotiated. That really is just a headwind that we've got to work to overcome. There is the Edmonton South Trans Mountain recall rights. We know that 2 of the 15 tanks will be recalled at the time that Trans Mountain expansion actually goes into service.
And finally, again, there is generally, general uncertainty around Western Canadian infrastructure. At the end of the day, as I have talked about a couple of times, incremental takeaway capacity is a benefit to us and we would like to see that, but lack of it is not necessarily a downside. But all in all, we've got a great set of assets with a lot of solid fundamentals associated with it. And that's all I've got today.
About 20 minutes ahead of time, we'll go ahead and start the question sessions. I think there's a microphone that's being circulated. If you just raise your hand and Steve and Kim and David will answer all the tough questions.
And if you could say your name and who you work for, for those of us who can't see that far.
Jeremy Tonet, JPMorgan. Steve, you talked about a few different times how the private equity market seems to be assigning more value to some of these assets than where the public markets are. You've already divested TMX. Is this something that you can look to do further that assets that are kind of non contiguous to non core, if you could look to play that inverse multiple arbitrage there and reinvest in other growth projects or buyback stock? Or how do you think about addressing those that inconsistency?
Yes. So, Jeremy, it's something that we look at all the time. We've done some divestitures, as I mentioned, like in the terminal sector over the years. There may be some opportunities on that with select G and P. A number of our G and P positions, specifically, we like our position in Haynesville, we like our position in the Bakken, that's integrated downstream with our assets, so is our Eagle Ford Gathering.
So, there are a lot of other benefits to that, but there may be some select opportunities on the GMP front that are worth exploring. But I don't think of those as being particularly needle moving. We'll continue to look at the opportunities to recycle capital appropriately. And as I said, we've done that over the years, but it's been relatively modest.
Great. Just one more. Kim, on Slide 50, I think it was, you're talking about kind of bridging a few years back to now kind of the waterfall. If we look forward a few years, are there kind of some headwinds we should be thinking about here as far as what could be erosion of the base EBITDA, what kind of contract rolls in some of these FERC pipes? Just kind of how big that is and just
if you could expand a
little bit there, that'd be helpful. Thanks.
Sure. On the FERC, on the interstate pipes, on the contract rollovers there, And we provide that slide in the appendix. Slide 93. And you can see that for 2020, about 0.3% of our earnings our total segment earnings before DD and A is exposed and about 2.6 percent in 2021. So I would say 0.9% in 2020 as opposed to 0.6%.
And that's with just to point out, that's without taking into account what gets that's not a net number. That's the number associated with that. It does not count what we might experience on additional growth projects, etcetera.
Is there anything else like this that we should be thinking about going forward with Jones Act or anything else or
We will have rollovers on the Jones Act ships. I think our average 58,000. You've got some that are above that, some that are below that. But the market right now is in the $50,000 to $50,000 a day range and we expect that there'll be continued retirements of those ships over time. So on average, not a big exposure there, but we do have some that will go to a lower rate just like we have some that will roll to a higher rate.
And so, there could be some difference in timing there.
Yes. The retirements are on vessels in the total fleet, not on our fleet, not on our part of that fleet. And then there's the 501 gs where we quantify the tax only exposure at a full run rate after you get out past rate moratoria, etcetera.
Hi, Jean Ann Salisbury from Bernstein. I had a question about the Texas Gulf Coast system. Do you expect most of the 4 BCFD from the 2 Permian pipes to move on your Gulf Coast system? And can it handle that much more? And is there revenue from that already assumed as kind of part of the GCX and PHP EBITDA?
Yes. So a couple of things. First, let me introduce our business unit presidents. So Tom Martin, Gas Pipeline Group President James Holland, President of the Products Pipeline Group Jesse Aranivas, President of CO2 and John Slosher, President of the Terminals Group. And so whatever I miss, Tom will cover.
But that 4 Bcf, those two projects did include takeaway capacity into our system. So we had, for example, some expansion that we're doing on the network to give people outlets through our system to get to LNG markets, to get to interconnects, to get to Mexico, etcetera. And so, some of that is included already. And where we, to our share, had economics, for example, in a lease payment to get that capacity, That's taken into account of how we look at the return, okay? But there's incremental beyond that, because there will be the need to optimize or balance the system as there are disruptions and flows, etcetera, etcetera.
There's a lot of gas coming in. The demand takeaway is going to be chunky. And so, we think that we will have good optimization opportunities. In Texas, we are free to buy and sell the gas to. We don't simply transport.
So, we have purchase and sales. We have storage. We have transport. And we think there will be incremental opportunities associated with that, that are largely not accounted for in the economics, small bits. So it's the direct compensation that we get for providing the additional takeaway capacity on our intrastate system and then there's, we think, opportunities beyond
that. Makes sense. And as a more broad question, you may disagree with this view, but many believe that the midstream build out for the shale revolution is probably at around its 7th inning in terms of spin. This would suggest falling growth CapEx and slower EBITDA growth in coming years. If 15% return projects are more like a $1,500,000,000 annual opportunity or even less and not the $2,000,000,000 to $3,000,000,000 that you forecast, Is KLMi comfortable with that even if it means less growth?
Well, we'll do what the market presents to us or what we can get out of the market. If we can find attractive returning projects as we have, we'll do them. And if we don't, as Kim said, we can always buy back our shares. And so, are we comfortable with that? Certainly, at current valuations, we'd be comfortable with that.
If we to the extent that we can find continue to find opportunities in that $2,000,000,000 to $3,000,000,000 range at the kind of returns that we've been getting, and as Kim showed you, we've been getting them, we would be better off deploying the capital there. But we have other options. We've generated, as Bruce pointed out, all this excess cash. We have good options with the uses that they put it to.
That's helpful. Thank you.
Gabe Maureen Mizuho. I just want to ask a couple of questions on CO2, if I could. First is on Talcott and the plans there. It seems like that's the lion's share of the bulk of the future expansion CapEx there over the next decade. But you're also projecting returns there that aren't that high from, I think, Kim's statement around what your IRRs are on share buybacks.
Can you, I guess, justify the plans for Talcott and also how much of that spend really is in your COT backlog right now? Yes. We do have
a Phase 3 in our backlog, but a decision to proceed or not to proceed on Phase 3 will depend on what the project looks like and particularly what it looks like under the oil price environment that we're experiencing today. We're not we haven't FID ed that and we're not launching into Phase III right now. We want to see we've been doing some work to kind of prove it out and Jesse and the team have done a good job there. And then I think we want to see where we feel comfortable with the oil price and we want to be able to clear that at a good return. And I think we'll actually elevate our return threshold on tall cotton because it is what we've done 2 phases that didn't turn out exactly as we'd hoped.
And I think we're going to want to be confident that we have a return with a margin of safety built in. Long way of saying is the jury is still out on whether we invest in Talcott Phase 3 in the current environment. Still some more work to do.
Thanks, Steve. And I can follow-up Bloomberg had with more CO2, Bloomberg headlines are not. Twofold question. One is, can you talk about the tax ramifications if you were to sell that business, how quickly you're depreciating it even after you wrote that business up of years ago with the consolidation? And I guess the second part is thoughts again on selling the whole thing versus separating out S and T versus production?
Okay. I'll take the last part of that and let somebody else answer the tax question. So, it is a separable business. The S and T business could be separated from the EOR business. It's about, I'd say, Jesse, like 60% is going to 3rd party uses of CO2.
So, we're transporting, we're developing, supporting and selling CO2 for 3rd party uses as well as our own. You'd obviously have to have some kind of an appropriate contract or transfer arrangement in place in order to be able to separate those 2 because EOR assets need a secure supply of CO2 in order to be independently viable, but it can be done. In terms of the tax and level of tax depreciation?
Yes, I don't know what the tax basis is on that asset offhand. But if any time we consider a transaction, we're always going to take those taxes into account in determining how much value comes back to KMI. So, they would be considered in any transaction we consider.
Michael Blum, Wells Fargo. So, Rich, on the last earnings call, you mentioned that you've gotten a lot of feedback from investors on capital allocation. And then I think it's Slide 52. Kim went through the capital allocation priorities. And I think, Kim, just to paraphrase you, it seemed like you said the balance sheet and the dividend are kind of set and then it's really just capital projects and share purchases as the two options.
And I guess my question is, what is the feedback that if you could share that you're getting from investors? And why is balance sheet and dividend not also up for discussion? Perhaps that could that you could drive leverage lower, you could change your dividend policy again. Just want to get your thoughts on all that.
Well, let me just say that we look at all 4 of these and obviously all 4 of these are viable uses of our cash flow. What we're saying is we established this target for debt at 4 and a half times and we've made that. Does that mean we'll never pay down another dollar of debt? No, certainly not. But it is not of the same priority.
It was when our debt was higher before we got the recent upgrades on the dividend side we've laid out a path in 2017 for where we would be at 2018, 2019, and 2020. That gets pretty rare for companies of our size to do that, and we're committed to do that a dollar this year and a dollar 25 next year beyond that We will look at our cash flow and decide what makes sense. I think longer term The dividend at some point will start tracking what our inherent growth in our fund generation is across the company. So it's not that it's going to stay at $1.25 forever. It's not going to go up $0.25 every year either in likelihood.
Now I think Kim covered very well the difference between capital projects and share repurchases. The two comments I would add to that is that, and Steve has said this repeatedly, we will not chase deals just to do deals on the capital project side if they don't meet our hurdles. And that means taking into account what an appropriate terminal value is. That means taking into account the sanctity of contracts, the support of the credit on the other side. We just won't do those deals.
But I think, as Kim said, you have an attractive fallback, if you will. To the extent we have additional capital, buying shares at this point in time at 9a half times EBITDA is pretty well a no brainer. That's a very nice return. And if you just look at it, if we can do capital projects at 6 or 7 times or 5.2, then we'll do them, but we're not going to try to do capital projects at 8, 8a half, 9 times because we'd be better off to buy back shares from a risk reward basis. So I hope that gives you a little feel.
I think it's a very good sweet spot to be in where we anticipate generating capital to cover all of these needs and being able to vary among these four uses.
Hey, guys. Michael Lapides from Goldman Sachs. Press releases out this week regarding some opportunities with you guys in Tallgrass. Just curious, when you look across the portfolio of assets that you own, where you think the greatest opportunities may exist for either repurposing or reversing existing assets?
Okay. Well, I think that's a reasonably good example of it. We have some underutilized capacity on our Cheyenne Plains system, which is a gas system today. And on our Wick system, our med boat lateral is actually dual piped. And so we've got some flexibility there to take one of those assets and convert it.
And I think that's look, we think that it's an opportunity that the market needs. We've got a long way to go to make sure we've got commitments in order to proceed with that project and we don't have in our backlog or anything like that. But that's I think a pretty good example. If you look around other assets where we have increasing utilization in our gas network, which makes that those pipes less viable as alternatives for repurposing, The only places really that doesn't have that characteristic is probably Gruvy and FEP, and those probably are not a good fit for like a crude or an NGL opportunity. So, I think this is probably a decent example of maybe the best example of where we've got that kind of opportunity.
I think, Cochin, you could as Dax pointed out, you've got pipe in the ground between Alberta and Chicago. That pipe is going to be valuable in one kind of service or another for a long time to come. It's been changed out and put in different service and moved a different direction in the past and that opportunity may present itself again. Okay. Yes, one other option.
We have some gas capacity. Our Hill Country pipeline from West Texas to the Gulf Coast that could be an NGL candidate, for example.
Christine Cho, Barclays. I just want to get I just want to see what you're assuming in your natural gas guidance. So three things. Of the $100,000,000 that you talk about with the FERC risk, you said that was a run rate. How much of that is assumed in '19?
2nd, I think you have some Mid Continent Express roll off this year. So curious just to know what you're assuming there on the recontracting? And then 3rd, just wanted to confirm that there's no you haven't risked ruby numbers in that number as well.
Okay. So, on the 501 gs, we do not have in our current budget any adjustment for 501 gs related. I mean, if you look at TGP's rate moratorium runs until November of this year. Now, if we can get a good settlement, we'll take it,
right?
And if it makes economic sense to do, we'll do it. But we're not anticipating we don't have anticipated in our budget any adjustment for 501 gs for 2019, okay? And again, if we do get a settlement, that'll be good news and we'll adjust our outlook accordingly. On MEP, yes, we do have forecasted in our 2019 budget our assumptions on rollovers for MEP. Now I'll point out MEP has been the MEP has seen decline in basis, and then it saw about this time last year a pretty significant uptick in basis to levels that we hadn't seen since the pipe was built.
And so there's been some good recovery. Now it's retrenched a little bit from there, but the renewal rates are looking much better than they did 1.5 years or 2 years ago. And your last question on Ruby, so Ruby, we don't have we have an assumed refinancing, relatively small refinancing assumed in there in our capital plans, but we don't have any assumption, for example, around PG and E going away. As Kim said, there's reasons to think that based on the history there, the contracts for prior approvals, the track record, the fact that they serve a core, etcetera, we would expect those to continue.
And just a clarification on MEP, are you assuming all of the capacity gets contracted at a lower rate or are you here hitting the capacity too?
Whatever capacity we had under renewal, we adjusted for current assumptions and embedded that in 2019. That's right, Tom.
And then, Kim, you talked about the returns coming in better than when you presented these projects to the Board. Is that it sounds like it was just primarily a function of the cost coming in better, but was there anything on the revenue side as well that helped those returns?
Yes. So there is on the revenue side. On the revenue side, it's largely associated on the gathering assets where we've had higher volumes. And then the cost side is really where we did a little bit better was where we have the fixed price contracts there. That's set because generally when we get approval from the Board, we already have signed up those long term contracts on the interstate or the large diameter pipes.
Dennis Coleman, BVVAC. Just a quick question on Canada. Some good detail provided on what growth projects you might have there and the financial flexibility. I wonder if you might we've been hearing anecdotally that the M and A market might be a little weaker there or the ability to attract new capital. So I wonder if you just talk a little bit about the M and A market in Canada and your views?
Yes. I'll start and then Dax can fill it in. I mean, I think generally the midstream sector up there is fairly well capitalized, has balance sheet in good shape and has not been impacted to the same extent as some of the producer community have. So, we think it's still a decent market up there.
Yes, I would agree with that. The thing that I would add is, think that there are not a lot of you don't see a lot of deals up there because I don't think assets come up that often. A lot of times you see singular assets here and there, but large packages of assets don't come up that often. So again, it's not that there's I wouldn't extrapolate not seeing a lot of deals conclude that there's not a lot of demand. I think there is actually a lot of capital looking for deals and certainly looking for the right types of acquisitions.
And so I think overall it's generally it's generally reasonably robust in terms of desire and expectations, even though you don't see a whole lot of stuff print.
Danilo Zhivani with BMO Capital Markets.
With KML, how do you think about the treatment of Goshen
in the evaluation of potential sale? Do you how do you treat the Canadian portion of the entire pipeline? What are your thoughts on how that's a
good question. I would say the most fundamental tenant is probably that operationally it's very difficult to just simply meet Cleveland Cochin at the border and say, it's run as one pipeline. We put stuff in the U. S. Side and obviously we take stuff out in Canada.
And so operationally it's reasonably well integrated. So splitting that up would be pretty difficult. So I think at the end of the day, whatever wherever the strategic process goes, it is more likely than not that Cogent resides in one place.
Jeremy Tonet, JPMorgan. I was just wondering, I don't know if you touched on the Colt project too much here, but if you could expand a bit there as far as what do you see as the competitive advantages of that project? It seems like there's a few others that are in the mix there. And how do you think about, I guess, the regulatory process for getting something offshore? It seems like the last years ago when the last facility was built, it wasn't easy process then.
It seems like things have only got more difficult since. So, how do you think about those things?
Okay. Yes. So, there are something like 7 proposals along the U. S. Gulf Coast and they're obviously not all going to get built.
But as we look at, we think it makes some sense to have 1 in the Corpus area, 1 in the Houston area, and that's what Colt is aimed at. The process the approval process is permitting at MARAD, MARAD. So, we would file an application at MARAD. We would do that presumably having contracts in place, right? And we're not doing the project unless we have contracts in place.
And so right now, it's a competitive process. There are some significant there's significant shipper interest, and they're going to pick 1, frankly, I think, and that's how this will play out, at least in what we see in the Houston area project. Initially, our perspective was the MAY RAD permitting process was only open to 1. It's not clear that that's true, but I think the market in the Houston area is probably open to 1. And so it's a competitive kind of footrace right now.
Great. And shifting gears, I guess, to the Texas Interstate Gas System. It seems like building GCX and PHAP points a lot of gas towards your system. So I was wondering if you could expand a bit more as far as what opportunities that presents for you guys downstream debottlenecking and how meaningful could that be for you guys within the whole Kindred complex?
Yes. So, we do think there's good opportunity there because it's an awful lot of incremental gas that's coming to that system. Now, that's a very good system that touches a lot of markets, Mexico, LNG, the industrial development along the existing industrial as well as the new development along the ship channel as well as the utility loads. So, it's a right now, it's kind of a 5 Bcf a day, day in, day out system, which is a bit unusual, fairly high utilization. We think, as I said in response to Gene Anne, I mean, we've incorporated some debottlenecking to go on to make sure that we can handle that gas when it comes.
But I think the opportunities that will be there to make sure that, that gas has a home when it arrives and including when there are disruptions forecast, but I think we'll have some meaningful opportunity to buy and sell the gas and to put it in storage and to find other markets in which to place it. So, it's a great network that touches a lot of markets and we're looking forward to having 4 BCF show up at our doorstep, let me just put it that way.
Becca? Becca Followill, U. S. Capital. In looking at Slide 127, it looks like you're relying a lot on tall cotton to help stem the declines at Sacrock.
Can you talk about what you do different on Phase 3 versus Phases 1 and 2 that didn't pan out?
Yes. So what we're looking at in Tall Cotton is primarily optimizing the spacing. So we did some 20 acre work, we did some 10 acre work, and we think we've got the right fit at 15 acre spacing. But as I said in response to Gabe earlier, I mean, we're going to look at that project with a bit of a higher hurdle rate and look at it in light of current oil prices and right now have not FID ed. So there's still some more work to be done and still some more observation to be done, if you will.
Now on the good news front, Sacrock continues to outperform, and we've had good development good results on our Hawaii project, which is targeting the transition zone. That's a development that has not rolled over yet. It's been performing well above what we planned and expected. We're starting to see similar response in the East Blanc. And as David mentioned, when he was presenting the budget, we'll look within CO2 and if it doesn't make sense to put capital into all cotton, we've got opportunities maybe incrementally to put it into Sacrock.
And if we don't, then we won't spend it, just simply, and we'll find other things to do with it. So, tall cotton, again, decision not made yet. Sacrock might provide incremental opportunities to put capital to work beyond what we had in the 2019 budget, and it's typical for us to shift that around within our CO2 segment.
We've done additional
sizing for it at Tall Cotton as well to get ourselves more comfortable with what we see.
Ray, I think over there.
Hey, guys. Michael Lapides of Goldman with one follow-up. And this can be a little bit of an unusual question. It's more than anything. Your guidance assumes the share count grows about 50,000,000 shares, But you also have the ability without exercising or utilizing a lot of cash to actually keep that from happening and therefore the DCF per share would be a few percent higher.
Why not at least take the limited step in terms of utilizing the buyback just to keep the share count flat?
Well, certainly we look at that as a use of cash, as I talked about, and try to balance that with the other needs for the cash. We certainly, as I've said, are very interested in buybacks. But as I think Kim and Steve have talked about, if we can attract capital projects that are going to give us better returns and that on a risk adjusted constantly looking at the opportunities. We bought a couple of 100,000,000 earlier in the year. We bought 25,000,000 in the 4th quarter in terms of shares, dollars 25,000,000 And we're going to continue to do that.
We've spent $525,000,000 out of a board authorization of $2,000,000,000 And I believe we will be doing more as time goes on. How much of it in 2019? How much of it in 2020? We don't know yet. And I think also, as we've talked about, if there are divestitures, for example, we will utilize enough of those funds to keep our debt to EBITDA ratio constant at the 4.5 level.
We're going to sell those at something greater than 4.5 certainly and that will give us excess firepower to utilize if we so choose for a share buyback while maintaining our discipline on the 4.5x multiple. So I think there are opportunities. We just have to see how it progresses. Again, the 50,000,000 increased shares was a onetime thing, as David explained, by virtue of the preferred converting, which you did in the Q4.
And I would add that taking it in isolation isn't really appropriate. You got to look at the reduced dividends that we're paying, right? So I talked about $128,000,000 reduced dividend payments on the preferred equity. It's actually 100 and 6 on a full year basis because they converted in 2018. So on a per share basis, it's actually accretive when you take that all into account, the conversion, the incremental shares reduced by the preferred dividend payments that we are no longer paying.
Hi, Keith Stanley from Wolfe Research. Steve, when you talked about if you were to assess a theoretical CO2 sale that one of the variables you'd have to look at is confidence in the market moving the valuation multiple higher on a sale. So how would you think about and evaluate that? And do you have an opinion of how much the market maybe is hurting the multiple today, owning the CO2 business relative to if you didn't own it?
Yes. I mean, not surprisingly, we've looked at numbers and I think you'd have to reasonably well, it depends on the price obviously. And you'd have to look for some increase in the multiple on the remaining assets because they've been derisked for the commodity price and in the order of a half to a turn kind of be the down multiple. And yes, we look at or certainly hear about CO2 and how it fits or doesn't fit or is perceived to in our portfolio. But really the way we make our decisions in CO2 and we'll continue to is, are we getting good returns and are we confident of those returns when we make an incremental investment decision.
And if an opportunity to transact comes along, then it comes along. But we're not going to live our lives that way. We're going to keep working on that business and making everything we can out of it.
One quick follow-up. What is the oil price assumption on Slide 127 with the outlook for the business?
65.
65. Thank you.
60 for 'nineteen and 65 beyond.
Okay. Any other questions? Okay. Well, thank you very much and I want to give a special thanks to the team who put all this together. Thank you.
Let's give them a round of applause.