Hi, everybody. Good morning. Thank you for your interest in Williams, and welcome to the 2019 Williams Analyst Day. My name's Brett Krieg. I lead investor relations for The Williams Companies. I'd like to take a quick moment to both thank and congratulate John Porter. John Porter's been leading the IR effort here at Williams for about eight years, and I know he's been a great asset to the investors and research analysts that follow Williams. Thank you, John. I'd also like to introduce my colleague, Grace Scott. I think many of you have spoken with Grace before, but if not, take a moment to meet her. She's in the back of the room, too. Some housekeeping items real quick. The main entrance to the room is at the back here, and we'd ask if you have to leave during the program to use that rear entrance.
Also, if everyone could silence their cell phones, that would be great, too. With our focus on safety, let's all take a moment and find the emergency exits, though. There's one here at the front and then the main entrance at the rear. Some of our statements today will be forward-looking statements, and we will also be discussing non-GAAP financial measures. There's some important information on these two topics in the presentation materials, and I encourage you to take a look at those discussions. If we think about the agenda. Today, we're going to first hear from CEO, Alan Armstrong. We'll hear from Chief Operating Officer, Michael Dunn. Chad Zamarin, Corporate Strategic Development Vice President, will follow Michael after a short break. John Chandler, Chief Financial Officer, will round out the prepared remarks.
After that, we'll have a panel Q&A discussion where our speakers will be joined by Debbie Cowan, Senior Vice President and Chief Human Resources Officer, and Lane Wilson, our General Counsel. From a schedule standpoint, you can see we're hoping to wrap up by about noon today, and we will have a short break after Michael finishes his comments. With that, we have a short video that'll kick off the program, and then we'll hear from Alan Armstrong.
For years, companies like Williams have quietly delivered the natural gas that is fueling today's growing clean energy economy. Natural gas is safely moving across the nation, delivering an affordable fuel source, creating thousands of jobs, and driving a resurgence in U.S. manufacturing. Natural gas heats 76 million homes, generates 30% of the nation's electricity, efficiently fuels fleets, and enables manufacturers to produce the essentials that continue to improve our daily lives. Parts that make vehicles lightweight, fuel efficient, and safer. Cell phones, computer keyboards and monitors, even clothes. Thanks to increased natural gas production in the United States, up 37% since 1990, greenhouse gas emissions have decreased by 17%. Imagine the impact of removing more than 7 million gasoline-powered cars from our roads for a year.
Williams' reductions in greenhouse gas emissions alone over the past decade is equivalent to just that, and there are big opportunities to do even more. Natural gas is an important part of the mix in helping the U.S. leverage clean energy. As an always on, affordable solution, natural gas is there when the sun isn't shining and the wind isn't blowing. Together, the mix of renewables and natural gas will ensure the reliable delivery of clean energy for decades to come. As world economies continue to develop, U.S. energy companies like Williams are positioned to reliably serve the demand for environmentally responsible, clean natural gas as a replacement for coal and oil to reduce carbon emissions and electricity generation while powering global growth. While the world gains momentum from the solutions and infrastructure we've already created, Williams is ready to meet the demands of our clean energy future.
That's how we make energy happen.
Well, thank you all for being here this morning. I was so enthralled in that video, I kind of forgot I need to come up here and speak. We're really, really pleased to have such a good group here this morning, and excited to have the presentation here at the New York Stock Exchange. Beautiful room and a great group of people. We've got a lot of great information about Williams to share with you today. I'll just get right into it. First, here on slide five. The last time we held an analyst day was in May of 2018, a lot has changed since then, certainly. Through all these changes, including significant asset sales, we have still delivered on that guidance.
As you can see here, we expect to meet or beat all the financial goals that we set out 19 months ago. Here, as we close out 2019, we've got a pretty good bead on where we're going to be at the end of the year. We expect to achieve these goals on even less growth capital spending than originally planned. Looking at the specific numbers, we expect to come in right at the midpoint of our adjusted EBITDA range, which is at the $5 billion mark. That was an 8% increase over our 2018 actuals. I'll remind you, our 2018 actuals were even a little higher than our midpoint of 2018. We expect to exceed the midpoint on the DCF guidance range, which was also an 8% growth over 2018 actuals.
That midpoint was $3.1 billion, and we do expect to come in above that here for 2019. Another very important metric that we have also exceeded versus original guidance was on our credit metrics, where we now expect to end the year under 4.5
Versus the original guidance of less than 4.75. Another guidance from that original that we're exceeding. Finally, on dividend growth, and coverage, we came in right in line with what we laid out about three years ago. If you recall, in January of 2017, we laid out a 10%-15% dividend growth rate. What we have achieved is a 12.5% CAGR over that three-year period, with about 12% here in 2019. Overall, continuing to hit on these numbers. I think another really important number, obviously there's at the bottom on adjusted EPS, and though we did not provide guidance on EPS back in May of 2018, we did show net income growth of 12%, and we now expect to deliver adjusted EPS growth of over 20% over our 2018.
In total, we delivered even more than our guidance in the face of asset sales, this has allowed us to accelerate credit metric improvement. That provides you a nice reconciliation of what we told you at the last Analyst Day. Now let's move to today's message of continued improvement. I'm going to go over here, what we're going to talk about today, you can see, first of all, on strategy, we're going to hit some of the fundamentals that'll continue to drive our business. We'll talk about the fact that we continue to invest along right on top of our existing asset base, which is very competitively advantaged, that's allowing us to have outsize returns, at lower risk versus the broader industry base.
It certainly is powerful to have the right assets positioned to take advantage of the growth up against the natural gas demand growth that we continue to enjoy, and we have the organizational capabilities in place to ensure that value is for our shareholders to enjoy. We also will review our financial performance for the last three years and what drivers of that performance have been. The punchline on that is that we now expect to deliver three years of meeting or beating our guidance on all key financial metrics. We will also lay out our 2020 guidance and show the actual positive free cash flow that we plan to deliver. This is after an expected 5% increase in the dividend and all capital investments. This is a lot of different versions out there floating around free cash flow.
We are going to show you, we're going to be delivering true free cash flow after dividend, after all capital investment here for 2020. We're excited about that. Michael will review our key internal management metrics and show how we use those to measure our execution and to drive financial performance. I would tell you that has been a key part of our success, is having management metrics that underlie these key financial metrics that we constantly track and we really run our business to. You'll see a nice review of that. Next, on the growth side, we'll talk about the catalysts that will drive continued growth, and that's really across a very wide range of opportunities. We're really very lucky to have so many different areas contributing and so many different ways to win across our portfolio.
We'll discuss why our cash flows are now so predictable and proven by the fact that we have been in line or beat Street consensus now for 15 consecutive quarters. The drivers of this predictability have been the lack of commodity price exposure, the long-term nature of our contracts, the diversity of our asset base, and very importantly, the crisp execution on delivering big capital projects. On asset valuation, we've talked a lot about this, and you're going to continue to hear more about this. We still believe that private investors really appreciate the solid and very reliable cash flows that come off of assets like ours, but they don't like the volatility of the stock price. This attraction is certainly driven by proven, predictable cash flows up against very low interest rates.
We continue to see a lot of attraction to investing alongside these cash flows and the yields off these assets. Frankly, the public market is not putting that much value on this spread. We continue to believe there's opportunity to arbitrage these different perspectives. I will tell you that certainly not all assets in the space are created equal. There are some deals on GMP assets that have certainly evaporated here over the last year or so. There is a very long list of successful deals, many of which have been our own. I would tell you from our perspective, the delta between the ones that are successful out in the market and are getting priced well, and the ones that are not, really boil down to how predictable and well-contracted those cash flows are over the long haul.
You're going to see some information from Chad about that. Certainly, we believe there's still quite a bit of opportunity out there to take advantage and monetize our assets, either through joint ventures like we did with Canadian Public Pension Fund or in other ways of taking advantage of the spread between the way the Street is valuing the cash flow off our assets versus what the private investors are willing to value. You'll see a little more from Chad on that. Finally, Chad is going to review the kind of value we've been able to generate via transactions where we've been rotating capital out of assets that are either in decline or very capital intensive, and with fairly low returns.
We've been rotating the value from those asset sales, we've been rotating that back into assets that are more complementary to our own assets and put cash flow down our own value chain. Really some great work there. I'll tell you, certainly that's been helping us drive this continued improvement in our financial metrics that you see. Just in summarizing on this note, I would say Williams is in a very strong and growing market. We are very well-run and well-positioned company, and we have a very sustainable business model. That's the takeaway I would hope you would get today. We do believe that natural gas should be recognized as a cornerstone of the nation's prosperity in the 21st century, and we're going to go through some of that here in just a minute around the macro.
Certainly, there's a lot of loud voices out there that are not rooted in facts and certainly not rooted in the realities that we have as a growing energy market. We've got to do a better job of laying out really solid plans for how we can both grow energy needs, keep up with growing energy needs around the world, and at the same time, reduce the carbon that's being emitted as well. We think natural gas is extremely well-positioned to do that, and we'll talk some more about that today. Here on, just starting into slide seven, I'm going to go through about three realities here that we think it's important for an investor to understand. One of the things you really have to understand about Williams as an investor, and it is really critical, this business is completely tied to natural gas demand.
The growth of our business is very much going to be on the backs of natural gas demand and the drivers for that. Understanding that in reality, and the fundamentals behind that, we think is very important. I'm going to spend a little bit of time on that. T He first one will be affordable natural gas is a critical part of the clean energy future. The second we'll hit is natural gas demand is growing and driven by emerging economies. Third, robust natural demand growth will require many production sources here in the U.S. we're going to hit on these realities. Just looking at slide eight here, the story starts right here in the U.S. here on slide eight, we show how powerful low-cost natural gas has been at driving emissions lower in the U.S.
It really is critical to remember, we did not start down this journey of replacing coal on the backs of emissions. Everybody now thinks that. Everybody thinks, well, that's how we got here. The truth is that the real change-out and transition of the fuel was because natural gas was so much lower cost. People started looking at what it was going to cost to clean up coal plants in terms of putting scrubbers on and reinvesting in that versus the future on natural gas. As people became more and more confident that we could keep natural gas low price for a long-term, that's really when we started seeing a dramatic investment in natural gas, and the market shares continue to increase with that.
You can see here what we've been able to accomplish in the U.S. in terms of CO2 emissions reductions, and really no other industrialized country has this kind of success. Impressively, and I think this is really critical as we think about the future, that not only have we lowered CO2 emissions, we've also lowered consumers' utility bills, and we've allowed for big investment in renewables to go on in the space. As we've lowered consumer prices, that's left room for the utilities to invest in renewables. We think that's very positive. We think it's needed, but we have to realize that it is that low-cost natural gas that's really driven a lot of this opportunity and the emission reductions that we've enjoyed. Moving on to slide nine here.
There's some things that if you look back as an investor and you stop and think about the fundamentals later, five, 10 years later, you look at something and go, "Well, why was that? That was so obvious. Why did we not think that would happen?" I think these fundamentals are some of those. The truth is that natural gas is abundant, and it is very clean, and it's very low cost. Those are fundamentals that are going to be very difficult to topple. Because we have the abundance and because it's an immediate opportunity to lower emissions in a meaningful way, we think natural gas and its low cost will continue to drive demand across the globe. As we look at the picture on renewables, this is really interesting, and I'll have to credit Michael Cembalest with JP Morgan on this analysis.
He came out with something here in March on a paper that really caught my attention, and it was called, the name of the article was "Mountains and Molehills." What he pointed out was that we always focus so big on renewables and how big they are and how fast they're growing. Take a look at how little renewables really are of our total end-use energy consumption. What you see here is on the left, in 2018, you can see what we really used as a globe in terms of end-use energy, and you can see that only 20% of the end-use energy is consumed in the form of electricity. Only 7% of that 20% is produced by renewables. To think that you can grow and take a lot of market share away is just not very practical.
We certainly are going to grow renewables very rapidly. We think that's a great thing. We think there's good opportunity to do that, but there is a limit of how fast and where you can apply that. When you start looking at replacing it when it's in direct fired use, the way you see around the rest of this pie, it's really hard to make electricity make sense into those markets because of the inefficiency of generating the power and then transmitting the power, and then using it for industrial uses. It's just not very conducive, and it's certainly much more expensive. In fact, if you tried to replace that 18% in there with electricity, it would be three to five times more expensive to replace that, even if we had adequate power at today's prices.
A lot to be understood if you really dig into the facts and really understand the limited scale of renewables as they exist today. I don't want that to come off that we don't think we should invest in renewables, nor that will be an important growth vehicle. We definitely think it will be, and we're all behind it, but we do think we have to really stay sober about the facts and really look at the data and the science that stands behind any solutions that we come up with to reduce emissions for the future. The next reality we talked about is natural gas demand is growing, and it's driven by emerging economies.
Just taking a look around the world, certainly while the U.S. has likely benefited the very most so far from very low cost natural gas production, the U.S.'s abundant gas production and large scale infrastructure has a lot to offer the rest of the world. Around 3 billion people still are cooking using solid fuel. That's, you often hear, it sounds like a fancy clean term, but the term is biomass. That really is things like wood, crop waste, charcoal, coal, and animal dung is what when you see the term biomass, that is what people are referring to. Then the other fuel that's used in a lot of these areas is kerosene as well on open fires and very inefficient stoves. A lot of energy is being consumed on that front today and really causing a lot of health problems around the world.
As you know, a lot of this kind of cooking and heating causes a lot of small particulate and really is being driven a lot of lung disease, and a lot of really damaging health. Unfortunately, a lot of that is very much imposed on women and young children who happen to be in and around those environments more. The list of improvements that natural gas has to this population space will go on and on for quite a while. As this very large and fast-growing population demands better living standards, tremendous pressure will be put on our available energy resources at the same time we work harder and harder to reduce carbon emissions. I would tell you, this is probably one of the biggest drivers, and I'm going to show some examples here about what this could mean.
This desire to improve the standard of living for this group of people is a big opportunity. I would tell you that there's going to be a lot of demands put on the countries and the politics to help solve these problems. The U.S. can and will help improve these conditions, and there's a lot of very feasible solutions that we can help solve through abundant natural gas reserves. If we look at here on slide 13, it's an interesting picture. Let me just explain it real quickly. This is showing the energy consumption levels at various standards of living around the world. You can see, no surprise there on the left, the U.S. with a very high standard of living and a very high energy per capita consumption.
Those are in MMBtus per person per year that we consume, and you can see it across the various groups. What's really dramatic here, obviously, is the disparity between very high human development and low human development, and even between low human development and high human development and medium and human. What has been happening, obviously, that's been driving a lot of energy consumption around the world has been people have been driving further and further to the left and people demanding a higher standard of living. You can see here, this is a 2018 number, and this estimates the world's total energy consumption of 651 quadrillion BTUs. You know when you start seeing those kind of numbers, you're getting into very theoretical, but this is what the current estimate was for 2018. If we look to see what kind of demands that would increase.
I'll tell you, lot of great analysts in here, and everybody's immediately looking, "Well, what time period is this? What's the growth rate?" There is no particular growth rate on this. This is just saying here is the order of magnitude movement as people on the right demand a higher standard of living. Just those on the right, not assuming any movement over on the left-hand side of the page, you can see a 39% increase in energy going up to 903 quadrillion BTUs. That's just if people on the left. That is not assuming that folks in Mexico and China and Brazil and Thailand want to have a higher style of living, which obviously they're very rapidly moving that direction. If you just isolated that, so that, again, this is 39% increase. If you just isolated and said, "Well, for. Assume that doesn't happen.
What if China, Brazil, Mexico, Iran, and Thailand want the same standard of living which we have here in the U.S.? That is 290 quadrillion BTUs or about a 45% increase. We're not looking at the combination of that here, but most likely, this is a combination of people on the right moving to the left, and people in high human development moving to very high human development, like here in the U.S. If you look at boiling this down, that's just a driver. Again, I wouldn't try to tell you that there's any growth rate that you can derive from that, but it certainly shows what is driving all the forecasts up into the right very hard on energy use around the world. This is an S&P Global Platts forecast from this year, and this is kind of the moderate growth rate case.
You can see this shows 49% growth from 2015 to 2040, and this is starting at about 621 quadrillion BTUs, and this only grows to 800 quadrillion. In the earlier thing we showed, that graph showed just moving to 900. This is a more moderate version, obviously through 2040, moving to 800. Now, the interesting thing about this, both these cases, that case that we just looked at previously assumes no population growth. If you add population growth against this, and a lot of that population growth is over to the right, you start to understand why people are so concerned about how we're going to be able to keep up with the energy use around the world. This is a big driver for natural gas demand.
As we look here on slide 17, we can see that natural gas is going to play a very essential role in global energy demand growth. A lot of for the reasons we talked about earlier, that it's cheap and it's clean. You can see here, and by the way, this is not unique to S&P Global. You can go look at any of these forecasts on this and you'll see these same kind of predictions. You can see that even with solar and wind growing at a 308% growth over this period, and which obviously is a pretty mighty growth rate. Even with that, you can see that natural gas surpasses the growth in solar and wind, going to 84 quadrillion BTUs of growth over this period. About 45% of the energy use is expected to come from natural gas.
That is some really big numbers, and this is why. Now, we all get frustrated on a quarterly and an annual basis that we don't see it doing exactly what we think it's going to do, but the fundamentals are in place to drive this kind of continued demand growth across the business. If we look here, just looking domestically, and this is a really interesting picture from my perspective because I'm such a nerd about following these forecasts. You can see the black diamonds there, on this forecast. That was the 2015 forecast from WoodMac on what they thought demand growth on U.S. natural gas was going to be. If you look at 2017, you can see we were weak on residential and commercial, so that was a warmer winter. You can see.
Now, obviously, this is just cumulative demand growth that you see here. In 2018, you can see in 2019, we were almost 20% higher than a 2015 forecast was. Now in 2018, I would tell you a lot of that was just colder weather during 2018. In 2019, what we've seen, and I think we're going to continue to see this, is that prices didn't come up the way these original forecasters thought they would. They thought we would start losing some of the demand on natural gas because prices were going to start coming up back in their 2015 forecast. In reality, what happened is prices have gone even lower, and so therefore, demand has continued to increase even more.
As you can see, looking at the picture here into 2023, for instance, you start to see power tapering off there, and a lot of that assumption is that gas prices rebound and coal starts to get some of that back along with renewables growth. That's what's causing that change there. If price doesn't come up, then that demand growth would be even higher. Interesting picture. We often hear about things being flat here. The truth is, they have not been flat, as you can see here, for the last four years, and it does not look like they're going flat anytime soon on the backs of both LNG and power gen growth, here in the U.S. as well as industrial growth. Pretty healthy-looking picture, I would tell you.
Again, I always think this is fascinating because people get very concerned about the impact of low natural gas prices on Williams. If you're worried about the quarter and you're worried about the very near term, that will cause drilling to pull back. Long term, low prices are going to create more and more demand, and that is what our business is geared off of. If we look about where the gas is going to come from to meet all this demand, we look across the. This is from November of 2018 to October of 2019, and you can see, obviously, the Marcellus and the Utica is carrying the big lift of natural gas. You can also see growth here, obviously in the Permian, the Haynesville, and the Eagle Ford, but you also see a lot of declines coming.
I would tell you, if we continue this very low-price environment that we're in, it is just going to put more and more pressure on places like the Marcellus and the Utica and the Haynesville to keep up. Because as prices come down, you're going to see, Michael's going to show some data on what the breakevens are across these various basins. Eventually, there's going to have to be enough price signal to support drilling in those low-cost basins for gas. Because, as you can see on this picture, and this is a big misunderstanding, I think, across the space, 65% of our gas today is still coming out of gas-directed drilling. It is not coming from oil-based drilling. It is not associated gas.
there is no way, if you do the math, there is no way that the associated gas can keep up with the demand, and if you didn't see a price signal for drilling, the decline across the natural gas basins. If you look at this picture, this is what we think it would take, and this is right off a WoodMac study that we worked with them on. This is what it would take to keep up if you stop drilling for natural gas. This is what the kind of demand growth and decline you would have to offset. Out in 2028, 75 Bcf today, up against total production today of about 89 Bcf today. There has to be a price signal available to keep gas supplies going.
Again, we're rather insensitive to that because eventually the supply on our system is going to meet whatever the demand is. We do not want to see prices spike. We'd much rather. We think if you see prices spike, you're going to kill variable transport on LNG, and you're going to start to see coal creep back into the power space pretty effectively. There's still a lot of coal-fired generation out there. That is what will impact long-term volumes on our system. Anyway, really interesting picture here. If you think about the price signal we actually have to have in these natural gas basins to continue to drive both the growth and to offset dramatic declines. We spent all this time talking about demand growth and really haven't even talked about Williams that much in this macro section.
Why are we so fixated, and why do we just keep pounding the table on this demand picture? This yellow line, I think this is the first time we've shown this, but this is really a nice graph. The yellow bar that you see there is the combination of our fully contracted transmission capacity, plus the actual gathering volumes that go through our system. This is where our top line comes from. This is exactly where our top line comes from for our revenues. You can see in the blue there, then that is our continued segment EBITDA. See the very nice correlation. It's very hard to see on this, but there were asset sales that you can see and the other EBITDA, which I guess is white on this monitor. I don't know what it looks like on there.
Yeah, you can see a little bit of gray on yours. That gray is basically our NGL and pet chem services piece that we've sold off. The blue is basically our continuing business, and the gray is what we sold off in terms of Geismar in Canada. You can see a very nice correlation there between the EBITDA and the sold-out transmission capacity and gathering volumes on our systems. If you take that same data and you index it to 100, so you index both the contracted transmission capacity and gathering volumes, and you index the continued segment EBITDA both at 100, along with Henry Hub natural gas and WTI crude, you can see there is no correlation.
You all are great analysts out there, but I really challenge any of you all to come up with any correlation here between our earnings and these commodity price swings. The fact is, our business is just going to be driven off of demand for natural gas. It is not being driven off these prices. Prices are going to be whatever they are to keep up with the demand. Really interesting picture. There's a lot of things that you can kind of drill down and think about this. There's a lot of things that cause changes throughout this. Really, I think, a really crisp picture of what's been going on within our cash flows. If we look at how our assets are positioned and why we are so confident that demand is going to show up as earnings in our business, it really is this.
We're in 14 different basins. We've got more than 600 customers across a very wide swath of our business. We're the nation's largest transmission system, and we handle 30% of the nation's natural gas. Much of the growth that is going to continue is going to be along this corridor that we own, primarily along Transco and Gulfstream. Obviously, we saw a nice little piece of growth with Northwest Pipeline here with the North Seattle lateral that we started up. Most of the growth in demand is going to be around Transco and with both exports and power generation still in these markets. Michael's going to show you a little more what's driving that.
the bottom line is we are extremely well-positioned, and very exposed to both the natural gas volume growth as well as the demand growth on our transmission systems. Another thing I really think is something we have a lot of positive reports out on is our track record of execution. Team has been executing extremely well, I would tell you, both on the operating side as well on the transaction side. I think we've done some of the very best transactions in the space, and Michael's going to walk you through how we've done on our operating metrics and our management metrics. It's very impressive numbers that we're continuing to improve on. Ce rtainly, safety is always, I think, a really good measure, particularly when you're measuring things like process safety incidents.
I think it's a really good measure of how tight a ship you're running, and you'll see that we continue to deliver on that as well. All of that is showing up in our financial performance. Here's the team that I'm so lucky to work with. I'll tell you, there's just a tremendous amount of dedication to making Williams the very best in the space from this group, and great experiences, that we bring to the table. This is the senior team at Williams right now, and the passion and energy that this group is bringing to the table right now, I think is unmatched across the industry, and I'm very thankful to get the chance to work with them.
I also will tell you, I think you'd be hard-pressed to find a better board across the industry as well, and this board's been pretty well reassembled since 2016. A lot of diverse experience, both upstream, some in the midstream and in the downstream, as well as some great experts on governance and finance as well amongst our board. Very diverse group of experiences. The one thing that's been so rewarding from my perspective about this group is they are very dogged about just staying very focused on long-term shareholder value creation, and they really work hard to not let anything get in the way of the team's focus on that. They've been around the track a few times, and they are very clear about, don't get stirred up about whatever the latest aggressive concerns are and voices.
Just stay focused on long-term value creation, and they have really held us to that. I'll tell you, I'm very thankful to get to work with this team. Another thing that this board has driven us to take a look at and get more aggressive about is on ESG issues. You can see in June of this last year, we published our first report on ESG, and that drove us from near the bottom on the Bloomberg ESG score, transparent disclosure score, up to second highest amongst peers with a 30% increase. It's no wonder, really. I think as we continue to lay out, we filed our first effort around the CDP, or the Carbon Disclosure Project, and so we will be filing our final report on that next year. We've got a lot of great things to show.
I would say from my perspective, the real impressive thing about how we're doing on ESG, we've always done a good job on this. It's just a matter of now we're actually putting press to it. You can see there, and you heard in the video, the kind of emissions reductions that we've been able to generate, 53% methane emissions reduction since 2012. I actually have to credit the Environmental Defense Fund for a little bit of that effort. Not because they were aggressive towards us, but we worked with them back in this kind of timeframe in 2011 and 2012. We worked with them to take a look at the emissions going on in and around our processing facilities out in the Rockies, and we started using infrared cameras to detect leaks in our system.
while we were lower than the EPA thought for their standard metrics, where they thought we should be, we actually found a lot of areas where we had emissions coming off our systems that we didn't know about, and we started tackling it from a safety perspective primarily. It's resulted in a 53% reduction in methane emissions around our systems, as well as on our Transco system. One of the big drivers there has been changing the way that we evacuate our pipelines and not in the past, when you had a pipeline repair, you would evacuate to the atmosphere, and we no longer do that. In most places, we compress the gas and capture it and put it back into the pipeline. A lot of great improvement.
Michael's going to talk through the process safety incidents, and certainly on a governance standpoint, I would tell you that we think that we, and the board, does a nice job of making sure that management's pay is tied to performance, through the metrics that we use. I think the investors reflect that through that say-on-pay score as well. Now moving to the management metrics that Michael's going to go into some depth on. We talked about that transmission capacity number. Starting at the bottom there, a 37% increase since 2016 on our transmission capacity across our systems and a 14% increase in gathered volumes across all of our retained gathering systems. Those are driving that yellow line up into the right, which is obviously driving our EBITDA up into the right. We also measure our return on invested capital.
We measure this both very specifically on a project-by-project basis, but we also keep measure of it across the whole portfolio and making sure that we're doing what we can to offset declines, pricing declines, cost control, and all of those things continue to drive that ROIC. as you'll see in a moment, then obviously that drives the long-term return on capital employed. John's going to go through this number and delve into this 12% return on invested capital. That's another measure that we track very closely, and this is how we've performed since 2016.
Finally, on operating efficiency, we measure what we call the operating margin ratio, probably one of the most important metrics that we use internally from a management metric because it's measuring how well we're doing at using our scale to drive costs out of our business and keep our overheads low. Part of that has been through our portfolio. When we see that we've got an asset that is driving a lot of overheads in the business because we don't have the scale in it. I'll tell you, Geismar, our ethylene cracker at Geismar, is probably a really good example of that because we didn't operate any other ethylene crackers. We had a big technical staff that was just associated with running that one ethylene cracker.
When we sold that, obviously, we didn't have all the overhead and technical support that went on with that. Today, if you look at how congruent and narrow our business focus is, it's allowed us to reduce a lot of the support cost and get right down to what we do the very, very best, which is the gathering and transmission and processing of natural gas. Those management metrics obviously convert into financial metrics. You can see here on the left, our adjusted EBITDA, the CAGR from 2016 to 2019 at a 7% clip, the distributable cash flow at a 10% clip. Now, don't think we're getting cute with the numbers there. The only reason we stopped that in 2017 was remember that we stopped the IDR, so we really didn't track DCF and didn't report DCF back when we had the WMB GPIDRs in place.
We didn't track that. Since we started tracking this 2017 through 2019, distributable cash flow up 10%, adjusted EPS up 17%. Again, that's on a CAGR basis. I should be clear about that. The ROSI improvement up 10%. That ROSI improvement, I wish that was on an absolute basis, but I don't want anybody walking away thinking we've improved our ROSI that much. That is a 10% improvement on the prior year's ROSI, and so that's just an increment. Again, that's a compound annual growth rate. Pretty impressive across-the-board financial performance that we've continued to deliver on about any measure you want to look at.
Looking to the future and thinking about our growth, we remain very convinced that the strong competitive advantages that we have, the footprint that we have, and the opportunities that we see out in front of us right now are going to continue to propel this 5%-7% growth rate that we've talked about in the past. I would tell you that it's based on some very low pricing assumptions that are in the deck right now. Even with the low pricing assumptions and the headwinds that we've been facing the last couple of years on that, even with that, we think we will continue this kind of 5%-7%. Particularly, we're talking about NGL margins there, where we've had relatively low NGL margins.
Not a very big piece of our portfolio, but when you're talking about percentage at the top line, obviously it does have an impact on your numbers. We're feeling very good about the continued growth of the business. A lot of people are going to look at our capital budget for this year, which is down to now $1.2 billion with the removal of NESE and say, "Well, how can you possibly drive growth with that low a capital budget?" As I've been telling a lot of you, we have a lot of projects both in the Northeast that continue to where our capital efficiency there just continues to improve dramatically. As well, in the deepwater Gulf of Mexico, where we're starting to see a lot of activity in tiebacks that do not require capital on our part for the most part.
Even without that capital investment, we're going to see some nice growth against latent capacity that we have in our business out there. Looking really quickly at the Williams stock price and the lack of improvement in this, I would tell you everything has been going up on the financial metrics except for the stock price. You can see here, this is pretty amazing to me. You've seen interest rates just continue to go down. You see in the blue there, you see the three-year average, and then in the yellow is the current year. You can see, obviously, interest rates over on the far right continuing to go down very rapidly, and that's obviously brought down yields on things like REITs and the top utilities. It has gone completely the opposite way for the yield on WMB stock and really across the sector.
I don't have a good explanation for you on that. I know there's a lot of frustration out there in this room on the same topic, but it is pretty amazing to me if you look at the growth rate and dividend out there, where we are more than twice the growth rate on dividends for the same period. The utilities are half the yield that we are against WMB, and especially given the very stable and strong coverage that we have on our dividend. Also, if you look at it on an enterprise value to EBITDA, next 12 months' EBITDA multiple, you can see Williams has moved down from a three-year average of 11.4 down to. That's pretty dramatic to go from a three-year average down and go a full turn down to the current multiples. Pretty big move against a long-term average.
You can also see on the right how that compares up against both utilities and REIT. We think eventually, the market has got to appreciate the yield on the dividend and the security of the dividend and the steady cash flows that we produce, because it certainly has happened in these other sectors. In closing, I will just say here, we really do believe that Williams is a very unique investment opportunity. The strategy that we have out there is extremely well-underpinned by very strong long-term fundamentals. We think we have the assets that are better than anybody's to take advantage of the natural gas demand, and we're very thankful for the execution we've been getting from our teams. Really about any measure you want to look at on execution, we've been doing a great job on that.
Finally, that's all winding up, turning itself into sustainable growth, very predictable cash flows. We continue to have the investment-grade credit metric, and I will tell you, we are really hell-bent on getting down to this 4.2 level that we've talked about in terms of our net debt to EBITDA ratio, and you're going to hear more from John on that today. We continue to maintain the strong dividend coverage ratio that we have as well. This business is very well-positioned. This company today is extremely well-run, and we have a very bright future here for the long term as we look at the kind of powerful fundamentals that stand behind natural gas demand.
With that, I think we're going to run a video, and then I'll turn it over to Michael Dunn to tell you a lot of the great things that are going on within the operations. Thank you very much.
Williams connects, and it's how we connect that fuels the future of clean energy. Our energy network is a transportation network unlike any other. Over 30,000 mi of pipelines handle 30% of the nation's natural gas. From coast to coast and beyond, our network connects the best supplies with the world's growing demand for clean energy. We reliably deliver clean natural gas to local utilities in major cities so consumers and businesses can enjoy affordable electricity, heat, and hot water, as well as cook with the heat source preferred by both professional and home chefs. In fact, every day, Williams delivers more than half of New York City's natural gas and serves major growing markets across the United States. We are ready to help bring this energy source to the world.
With our largest pipeline asset connecting through every U.S. state, with an LNG export facility currently under construction, no one else is positioned like Williams to connect the growing demand for clean energy in the United States and beyond. As investment in our global clean energy future accelerates, we are leading with a relentless commitment to safety, performance, and stewardship. We're meeting, and oftentimes exceeding, state and federal safety regulations as we plan projects and maintain our assets. We're preserving and protecting the environment for future generations while improving standards of living today. We're partnering with federal, state, and local leaders to build necessary infrastructure and operate in a way that reduces emissions and helps meet our shared clean energy goals. We're strengthening the hometown communities where we live and work by investing in conservation programs, disaster relief efforts, and STEM education initiatives.
We're rolling up our sleeves and working alongside our neighbors, donating thousands of hours of volunteer manpower each year. For more than a century, we've remained true to ourselves, doing the right thing every time. We stand behind our reputation as a dependable and trustworthy business run by people who deliver on our promises. People, safety, stewardship, and results fuel the clean energy economy. Williams connects them. That's how we make energy happen.
Good morning. It's great to be here with you again today and talk about Williams. I'm going to give you a perspective on our path to operational excellence, something we're very proud of, and talk about the metrics that we track every day to see how we're doing on that path to excellence. Also give you some details about each one of our three operating areas and how we're performing there. Thank you for being here, and thank you for your interest in Williams today. You heard Alan talk about the robust demand that we expect to see for natural gas coming in the future. Our assets are well-positioned to take advantage of this growing demand. We have a very large focus on the gathering business, our natural gas processing business, and our growing NGL services business.
Once again, our backbone transmission systems that are second to none across our industry. The fundamental foundation of a great business starts with operational excellence, and we track a lot of metrics in regard to our performance against these goals that we have.
Some of which that you see here on these building blocks that we put on the slide. This is really important for our customers to know that we're a reliable operator, for our investors to know that we're doing all these things to create financial strength for our business. It's great for our regulators to know that we're not only designing and constructing and operating our assets properly, but also the environmental stewardship that certainly is becoming more in the forefront of everybody's thoughts about our business and our industry today. Executing our projects well is incredibly important. You can certainly ruin your reputation very quickly whenever you don't go out and build a project properly, and we think we do that very well currently in our space. Ultimately, becoming a more efficient business is very important for not only our customers, but our investors.
Always like to start with safety and give you a perspective on how we're doing there, and I can tell you, our employees are doing a tremendous job eliminating hazards from our workplace. We've really made a concerted effort over the last several years to have our employees focusing on hazard recognition. You can see the graph on the left there. This is total recordable injury rate amongst our employee group and on a great trajectory there, 51% improvement on that metric since 2017, but handily beating our peer benchmark that you can see there in 2019. We've got work to do. This is a journey that never stops when it comes to safety. You can always have hazards in your workplace that aren't recognized, and our employees are doing a great job eliminating that.
The graph you see on the right is process safety metric, and typically, you would see this in a petrochemical or refinery industry, but it's also applicable to the midstream space. We have 74 assets that we operate that are required to be managed under process safety management rules. Once again, we took a very concerted effort to eliminate the process safety incidents. Typically, what this means is you've had a loss of primary containment, either from a vessel or a pipe. Doesn't mean you've had a rupture or an explosion, but something didn't go well. You had a relief valve or something like that didn't operate properly as it was supposed to. We track all those incidents. As you can see, a 77% improvement over the last two years in that metric as well.
This is incredibly important to maintain the protection of our assets, and we're definitely on the right trajectory there from a process safety standpoint. When it comes to reliability, this is something that first and foremost, us customers typically always want to talk about. How are we doing from a reliability standpoint? Are their gas volumes flowing the way they want them to? We track that in every one of our franchises. Every one of our operations management teams and our operators have a dashboard where they can know how their assets are performing. They can track every asset and determine where we're having problems with a specific piece of equipment within their franchise area so that they can go out and make corrections to that.
You can see the graph we put on here in the upper right, the trend that we've had over the last several years, absolutely doing what our customers expect us to do. We're nearly 100% of their volumes that they want to flow are flowing on a daily basis. This is obviously important to them. If their volumes don't flow, they don't get paid, and neither do we, frankly, on our GMP business. It's also the case on our transmission businesses as well. FERC has required every operator to put in their tariffs demand charge refunds. Whenever you don't move a customer's volume, when you hit a certain threshold, you actually have to pay the customers back for the payments that they're providing to you. This is important across every aspect of our business.
It's a reputational issue, and we do a great job at this in making sure that we're doing this well, but also communicating to our customers how we're doing there. The other thing that our team has done a great job internally, we've taken all of the data that we have, and we're finding ways to utilize that data to improve our reliability. One example of where our team has done that, you've probably heard us talk about and many of our peers and our customers talk about freeze-offs in the winter. Pipes freeze. The conditions are such that those pipes will freeze off. That makes a difficult proposition to correct that. We can take predictive analytics from our data today, and we can predict when a pipe is about to freeze off, and we do that on a real-time basis.
We can take quick action to go out and inject additional methanol into that pipe. We can tell our customers to do the same at the wellhead. We're utilizing that data on a real-time basis to predict when these pipes will freeze and improving our reliability for our assets as well as our customer volumes. You heard Alan talk about improving the efficiency in our business. One of the ways we evaluate that is the operating margin ratio. This tells us how much of our revenue is reaching the bottom line. It's a really important metric for us to track our own performance against previous years. We're also able to track this against our peer group with their publicly available quarterly data. I can tell you, we are bouncing right at the top of the peer group here on this.
We're within a few percentage points of being at the top. Our challenge is we have a very focused fee-based revenue model within our business. Many of our peers that we're challenged right here at the top with, they have a more focused commodity business where they do have some volatility in those commodity numbers, but it does give them the opportunity to take advantage of commodity basis differentials and improve their operating margin ratio. Because our business is very focused on our fee-based revenues, we have a very small commodity exposure. We do have a challenge being at the top there. I can tell you, we're finding ways to market more NGLs and market more gas around our assets.
We're continuing to take advantage of that, and you see our numbers showing some dramatic improvement since 2014. This is a metric that all of our franchise owners, they evaluate this, including our ROSI numbers that you heard Alan talk about, but it's a great metric for us to evaluate our performance against ourselves here. Another area that we watch incredibly closely is the execution of our projects. We put on the graph here how we're performing on our projects that we put in service this year that were over $75 million. This is just a schedule and cost analysis, but we do subjective analysis as well about how we perform the execution of our projects, how many notices of violations we potentially have, and how much interactions we have to have with the regulators out there.
This is a very objective metric where we can look at what did we think the project was going to cost, and when did we think we were going to have it in service. Doing very well on this metric, I will say that we had a couple of projects that did not meet our scheduled expectations, and that was intentional. We actually slowed a couple of projects down, slowed the capital investment in those projects to time when those came online with our customer expectations and their demands. Overall, great performance across our investment that we put in, about $1.7 billion of capital investment this year on our in-service projects, just slightly below budget at about 4%, and slightly ahead of schedule on our projects. This is a topic obviously you're hearing a lot more about. We're talking a lot more about this.
We did an ESG report earlier this year, but this is nothing new to Williams. We've been reducing emissions within our footprint for a long time now. Our Transco asset, for example, has had a tenfold decrease in NOx emissions over the last decade from us retrofitting our compressor facilities, taking advantage of an opportunity there to reduce emissions and make those assets more efficient. We recently joined the ONE Future Coalition. This is a peer group coalition that is committed to reducing methane emissions in our environment. We have a goal of 2025 for the industry to be 1% or below of a methane emission target. As you can see here on the chart, we're well beyond that already with our facilities. We're a fivefold improvement over that 2025 target, and we have more opportunity to continue to reduce our methane emissions here.
This is obviously nothing new to Williams, but we are certainly out there talking about what we're doing today. As you heard Alan, our scores are improving dramatically because now we're telling people what we've been able to do over the last several years. I'd like to take a little bit of a deeper dive into our three operating areas and tell you about their performance, but I will take an aside here to talk about our restructuring that we've done within the business. Jim Scheel, who has led our Northeast operating area for many years, many of you may know Jim, he retired just this week, and we enjoyed Jim's great leadership in the business for a long time. He did a great job for us. We took the opportunity through a lot of activities that we've had here.
We've had a lot of asset sales over the years, and we basically looked at our business and thought, "How can we restructure this business to be more efficient and to be more timely with information?" what we've done, Walt Bennett leads our West group today. Walt is going to take on the operation of all of our West GMP that he has today, and also the Northeast. Walt will be leading all of our gathering and processing business. We're going to take Northwest Pipeline that you see today in the West, and that will be reporting up through what is called today our Atlantic Gulf. Basically, we're going to rename Atlantic Gulf into Transmission in the Gulf of Mexico, but we'll still have three reporting segments that you have seen today and you've enjoyed the data and the transparency and information.
You'll still get that same information, just going to be structured a little bit differently going into 2020. In 2019, you'll still see it structured this way. 2020, we'll be moving Northwest Pipeline over into the segment called Atlantic Gulf, and that will continue to be led by Scott Hallam out of our Houston office. Jumping into the West segment today, and, as you can see, obviously a large geography, large amount of diversity that we have here within this segment of the business. Northwest Pipeline is an asset that we've been very proud of. This is an asset that really has a great moat of opportunity on the West Coast. In the Pacific Northwest, it's the only transmission provider west of the Cascade Mountains.
It's a large barrier to entry for any new pipelines to obviously move out there and cross that mountain pass and move into the high population centers of Portland and Seattle. You heard Alan talk about our North Seattle Lateral project that we just put in service last month. This was 159 million cubic feet per day of new capacity there. Some of you may have heard about discussions in Seattle about possibly making it illegal to connect any new buildings or businesses to natural gas. I can assure you the growth is there in Seattle today. That's why our customer came to us and wanted us to put a very substantial expansion in for them. This was about a 4% increase in the volume across all of Northwest Pipeline. A very large expansion there required in order to continue to meet our customer needs there in Seattle.
Since we last met, the remaining contract life that we have in our contracts in Northwest Pipeline's gone to 11 years. If you recall last time we spoke, it was nine years. There's still a lot of long-term demand and expectations that our customers will need Northwest Pipeline capacity for the foreseeable future. Obviously, a very good capacity, investment-grade rated companies that we have there. Primarily, it's utilities and LDCs is the component mix that we see in our customer base there with a small segment on the second place of the marketing group. That has our customer base there. Once again, very pleased with the performance of Northwest Pipeline and are doing very well there within our business.
This graph shows a depiction of our reserve capacity in the dark blue that we have on Northwest Pipeline, and then the steady and predictable volumes we've had from our gathering and processing business across the West. As you can see, very consistent performance, very predictable volumes we have there. It will tell you, we have a lot of diversity of customers, a lot of diversity of associated gas versus gas-directed customer base here, and that diversity benefits us. Obviously, we don't have any exposure to any one customer across this geography. We also have, and we feel like, a very predictable volume expectation here, and therefore, a very predictable EBITDA stream coming into the business. I want to point your eyes to the graphic at the bottom.
We have over $1 billion of free cash flow generation from these assets, and we would expect that to continue for the foreseeable future. This is very predictable. We feel very strongly about the business mix that we have here in the West, and obviously, throwing off a lot of cash that we can utilize in the rest of the business. Last time we met, we were really looking to grow our business in the Rockies through our acquisition of the Rocky Mountain Midstream that occurred shortly after we met last, and really doing well from an execution standpoint. Just this year, we've put new processing plants in to the tune of about 400 million cubic feet per day. Those are rapidly filling. We're processing about 300 million cubic feet per day, and it's growing every day with the new production that's coming online from the DJ Basin in Colorado.
The real story here is the integrated nature of the business that we've been able to achieve here with our Rocky Mountain Midstream business, our OPPL pipeline, and then once again, the Bluestem project that we've also recently announced last year that we've embarked upon to be able to get all the way to the Mont Belvieu Fractionation complex. We're able to give a lot of certainty to our customers up there on a Mont Belvieu index price. That's really the price that everybody wants for the NGLs, and we're able to do that now with a lot of certainty. We're capturing a lot of third-party business in the Rockies today because of our ability to take this gas, these NGLs, all the way to the Mont Belvieu complex through our Bluestem pipeline.
I'm proud to say we have all of our permits in hand for that project. Kansas and Oklahoma are a very friendly area to build pipelines, and we expect to begin construction on this project in 2020 and have it online no later than 2021. First quarter of 2021, excuse me. Still within the parameters that we established when we announced this project, $350 to $400 million of growth CapEx. That's the bulk of our growth CapEx in the West next year is associated with building this project, and still a very attractive EBITDA multiple of six times. Now I want to move to the Northeast, and I just want to remind you that Williams is the largest gatherer of gas in the Northeast. We have a very significant market share there.
Obviously, we all know about the headwinds that our producer customers are seeing there with low NGL and low natural gas prices. We've been able to capture very significant growth, even in that environment, as you can see in this graphic. It's at 1.5 billion cubic feet per day of growth, based on our estimated 2019 volumes that will come in by the end of the year. Obviously, we're here in December. We have a high expectation of meeting that average growth here for the year based on just a few days left in the year. Once again, incredible growth since 2012 of 240% on our assets there. I just want to continue to remind you about the backbone of infrastructure that we have built there. We're going to take every advantage of that going forward.
We do think that when gas prices rebound, and we obviously think they will, the demand story is there, and that gas has to be delivered, and we're going to capture the bulk of that growth in the Northeast through our GMP assets. I will tell you, though, when we had our conversations with our producer customers earlier this year, we certainly learned of their expectations for growth that were being tempered, obviously. We immediately took action to reduce our capital investment in the Northeast business in 2019. We took our investment on our growth capital down by about $370 million from what we expected to spend when we set our budgets at the beginning of the year.
As you saw from the previous graph, it did not impact our growth in 2019, and we certainly think that we have a backbone of infrastructure available to continue to capture that growth in 2020 and beyond once those customers on the producer side react to any price signals that they see out there in the marketplace. The key thing I want to point out here once again in this part of our business is the free cash flow generated by these assets. We expect to have over $1 billion of free cash flow generated from our Northeast GMP business in 2020, and we would expect that to continue beyond the 2020 timeframe for the foreseeable future. That is because we have that backbone infrastructure built today and our expansions beyond where we see those going into the future.
They'll be compression expansions, they'll be small looping projects, and they'll be very high-return, well-connect projects to continue our expansion opportunities there. What I'm telling you is the growth appetite that we have to invest there has been diminished, but we can still capture a lot of growth through those assets because of the infrastructure that we built up to today. We always like to show you a depiction of what we think the reserves life look like in our basins. 78% of the remaining risk reserves are in the Northeast. The Marcellus and Utica are very prolific reserve bases. If you look at this, and I will tell you, this is a very conservative view. Wood Mac pulled this together for us. This is basically their query of the major producers. There's certainly a lot of small producers that the data is not just as readily available.
I would tell you this is an incredibly conservative view of the future reserve base. If you look at the production that we see in the Northeast today, this over the 30 Bcf across all of the Marcellus and Utica, and you extrapolate that out over time based on these breakeven prices. This is 20 years of production life based on the reserves on this conservative estimate on this chart. We feel very good about our position there. We feel very good about our ability to capture these low breakeven price reserves that are going to come to market because of that robust demand that we see in the U.S. and the world. I'm moving to the Atlantic Gulf segment now, and I will tell you there's two words to describe this. You see it on the chart, irreplaceable infrastructure.
Between our Transco assets, where we have between four and five pipelines in that corridor, and we enjoy very lucrative opportunities to continue to expand that corridor. Our Deepwater Gulf of Mexico is once again another irreplaceable infrastructure asset that we own, and we will continue to enjoy opportunities coming off those assets that I'll describe here in a moment. Transco has been an incredible growth story. This is the largest FERC-regulated pipeline in the United States, and it's been the fastest-growing pipeline system for years, and we expect that to continue. By the end of this year, we will be a 17.4 Bcf per day pipeline. In 2022, as you can see, just under 19 billion cubic feet per day capacity is what we expect to have. At about $2.5 billion of revenue coming off this Transco asset alone by that timeframe.
We're still enjoying very nice multiples on our capital growth investment opportunities there. About a 6x multiple there, and then we would have a high expectation of continuing to be able to achieve those nice multiples on our growth capital projects in the foreseeable future. One of the things that we like to talk about is the interconnect capacity on Transco, and if you think about what the demand is in the U.S. today, it bounces around about 90 Bcf per day on average today. Very significant number. The interconnect capacity, and what I mean by that is the supply metering, the delivery metering, and our bidirectional metering that we have on the pipeline system totals 113 Bcf per day as of today. That's more than the total demand on a daily basis in the U.S.
You might ask, why is that important? I think it just shows the capability that the network that Transco has built, that it has, and the demand that we're continuing to see for people to come and interconnect with that pipeline asset. It's become an incredible network across the Eastern Seaboard and the Gulf of Mexico and the Northeastern U.S. for customers to get low-cost supplies to their growing and highly desirable demand markets. One of the areas that we're incredibly excited about is our interconnectivity to the growing LNG business that we see on the Gulf Coast and the Eastern Seaboard. We are direct connected to every LNG facility or indirectly connected to the ones on the Eastern Seaboard that are currently operating.
We are actively pursuing a number of projects as well from our Transco system to continue to connect to the expansions that are being proposed as well as the new brownfield and greenfield projects that are underway on the Gulf Coast. A great story here for our Transco system. We are the largest transmission provider today to all of these facilities, and we would expect that to continue for the future as well. It's about 2.25 billion cubic feet per day that we've been delivering today, and it's just peaking here in the October-November timeframe with the new projects that have just come online. When we're out talking to folks, we hear a lot of questions about coal and the demise of coal and the fact that there's no coal left and natural gas can't expand because of power generation.
I can tell you that's certainly not true. There's still a lot of coal capacity, and what we did on this slide is shown the coal capacity that's currently installed and operating today just in the states that Transco passes through. This is not a U.S. view. This is just the coal capacity. It's over 90,000 MW of coal today that is installed and operating. I'm not predicting when this will shut down, but what I'm telling you, there is an opportunity when these projects on the coal generation side shut down, there's going to be a great opportunity for Transco to take advantage of that and serve that new gas-fired generation that will be built alongside the renewable fleets that will continue to grow. There will be renewable penetration here.
Renewable certainly will take a lot of the market here, but we think natural gas has a great future here as well for baseload generation, as well as to back up the renewable projects that will certainly be built to replace this coal-fired generation when those plants are shut down. We have a huge backlog of projects that our project development teams are chasing today. We have nearly 20 projects that are very specific today that we know about, that we're actively talking to customers about. I can assure you, there are a lot more projects out there that are conceptual. None of these are things that we don't think we can achieve. We have high degree of expectation that we're going to be successful in this backlog of projects.
Run the gamut from power generation, LNG, as well as a lot of petrochemical activity that we're seeing in the Gulf Coast. We have about a $3 billion project in execution today that we're actively managing and have a high expectation of putting those into service over the next three years as well. I'll talk about a couple of those in a moment. One of the things that we hear a lot about is, "Can you still permit projects in the Northeast? Can you still build projects in the Northeast?" I can assure you, yes, we can, and yes, we will, and we have. You look at the chart here and you see how many projects we put into service over the last several years. A huge amount of capacity, nearly 4 billion cubic feet that we brought online just off our Transco system.
We have an additional 2 billion cubic feet per day in execution today. This is over $6.5 billion of investment that we've made or will be made within this Northeast area. We have high expectations of being able to continue to do this because the demand is there. There's a need there, the demand is there, we will continue to actively pursue projects here. I do want to give you an update on the Northeast Supply Enhancement project, the NESE project. You've probably seen the news that has been out there, where National Grid, through their regulator, the New York Public Service Commission, they had a show-cause order that the Public Service Commission put on them. They reached a settlement on that last week. They've ended their moratorium on new gas hookups.
They found a way to get through this winter to be able to do that and are certain that they can continue to serve those customers that they were holding off from connecting. What that means is they've solved their short-term problem, but the commission, through their settlement, has given them a timeframe to solve their long-term problem. Certainly, NESE was the solution to that long-term problem. We still think NESE is the solution to that long-term problem. The commission has ordered National Grid, our customer, to go out and do public meetings to talk about the solutions that they have thought about and the solutions that they have rejected and proposed. Obviously, we still believe NESE is the project to serve their long-term solutions.
We still like this project, but based on the settlement that was reached between National Grid and the New York Public Service Commission, we are not allocating any capital to the construction of this project in 2020 now. Once we receive our permits, which we'll continue to work on with New York and New Jersey, then we'll reallocate capital back to this project. Until we have permits in hand, the only activity that we'll have on the project is continuing to work on our projects, which obviously is somewhat of a minimal cost, and we'll await the issuance of permits. The settlement agreement between the Public Service Commission and National Grid requires them to have their long-term solution in place by the fall of 2021.
If you start thinking about the activities that have to occur there, we still believe NESE is the project that will be able to serve their long-term needs. We still have a contract in place with National Grid to perform on this project, and we still like this project, as I said, and we have a high expectation that this project will come online in 2021. We'll await the outcome of the process that National Grid has agreed to go through, and we'll await the issuance of our permits before we allocate any additional capital to this project. I did want to give you a quick rundown on a couple of exciting projects that we have undertaken and we are executing on today. The Leidy South project is one that we filed our FERC filing on in July of this year.
This is a project that's just under 600 million cubic feet per day and about a $500 million investment. This is moving gas along our existing Transco corridor. I know we talk about this a lot, but the beauty of Transco is the corridor that we have established. We have the opportunity to continue to expand that system by looping, and that's by building a parallel pipeline to our existing system, then dropping compression in at opportune locations to be able to move that gas through our existing corridor of systems there. We'll continue to find opportunities to do this. This is a great project to move National Fuel's Seneca Resources Company's gas as well as Cabot's gas from the Northeast production areas to markets in the Pennsylvania-New Jersey area. Expect to have this project online in the fourth quarter of 2021.
The other project we're incredibly excited about and just recently started talking a lot about, because of our successful open season, is the Regional Energy Access project. Once again, this is another great project taking advantage of Transco's existing corridor, looping and greenfield and brownfield compression. This project is to serve power generation in Pennsylvania and New Jersey, as well as local distribution companies in the state of New Jersey. The majority of these facilities are located in Pennsylvania, a much more friendly state to permit these projects in, and we designed it such that we can have a lot of assurance that we're going to get our permits on this project. This is one that we expect to be online toward the end of 2023, about a billion cubic feet per day of capacity, and we expect this to be between $800 million and $1 billion of investment.
Once again, these are projects that moved out of our backlog and moved into the forefront of execution, and we'll continue to announce these projects at a clip that we believe really is exciting for our customers. We're finding a lot of interest in the Transco corridor with the opportunities that we see there, but just another great example of the irreplaceable infrastructure we have in the Transco business. I wanted to give you a brief update on our settlement in principle on the Transco rate case. The settlement in principle was reached with our customers and their regulators in October. We expect to file this settlement in December, so we're working actively with our customers to execute that settlement agreement in its detailed fashion. Unfortunately, I won't be able to provide you a lot of information on that until that settlement is filed with the FERC.
That's just the rules that FERC has. We have to follow that. When we give you our update on our fourth quarter earnings call, we'll be able to give you a very fulsome update on this. We are going to have a rate increase associated with this settlement. We will have a path, as we've talked about, to our emissions reduction program on the Transco system that we'll be able to implement ultimately with our customers. We're very pleased with this settlement. We're very pleased with the process we went through and appreciative of our customers' interactions on that. We'll give you a much more fulsome update on this at our fourth quarter earnings call. Lastly, I wanted to talk about the Deepwater Gulf of Mexico in our Atlantic-Gulf segment. This is an incredibly active area right now, an area that we're very excited about.
We're excited because of the asset footprint that we have. There's a lot of low and no capital investment opportunities here where we're going to enjoy revenue coming into our system from our assets that have been installed, bought, and paid for over the last several years in the Gulf of Mexico. We really like our position here. We have really high-quality customers, really very high credit quality customers. We've mitigated our risk through the contracts that we have in place. If we have to deploy capital, we have a known and agreed-upon rate of return for that investment already. There's very large-scale reserves out here and very large capacity wells. Once again, our asset synergies are second to none here in the Gulf of Mexico.
I put this graph in here to give you a bit of a depiction on what a type curve looks like on an average well in the Midland Wolfcamp Permian area versus a Gulf of Mexico well. I want to make sure you understand that this is a percent of peak production. This is not a volume curve. This is percent of peak production that would come from these average wells. What we've done, this is a Perdido average in the Western Gulf of Mexico on our assets. In the yellow line, it's a Permian well in the Midland area in the orange or red line. Why we like the Gulf of Mexico, these reserves produce at a steady rate for a long time when these wells are drilled. I can assure you, the wells are not equivalent. The investment isn't either.
It's very expensive for the producers to drill out here. When you look at the estimated ultimate recovery of the wells in the Gulf of Mexico versus a Permian well, it's 10 to 15 times on an EUR basis on a Gulf of Mexico well versus a Permian well. That's why you see a lot of interest in the Gulf of Mexico. The producers obviously are very committed to this area. They invest a lot of capital up front, and those wells are very prolific for a long time. That's really a great opportunity for us to take advantage of our assets that we have out there. I'll talk more about that when I show you a chart here in a moment. I really wanted to talk about a couple of the exciting projects we just recently put online.
The Norphlet Pipeline is one that pulls very NGL-rich gas off the Shell Appomattox production that just came online last year, moves into our Mobile Bay processing facility onshore. This is an example where our customer agreed to fund all of the capital investment we had to make in our Mobile Bay processing plant to upgrade that facility to take on their very high GPM gas coming online. We didn't make any capital investment onshore on our assets there. They paid for those, and then we have a percent of liquids contract with our customer there to process that gas onshore. Once again, low to no capital investment there, and now we're enjoying the benefits of our existing asset base that we have. We've had new dedications in the Discovery system, Hadrian North, Buckskin, and Stampede, added about 150 Bcf of reserves.
Our Ballymore and Whale projects that we're working on actively today with those dedications from those customers. I just wanted to give you a quick snapshot of rig activity in the Gulf. 14 wells are currently being drilled. Very high utilization of rigs out there, as you can see on the chart. Once again, rig counts in the Gulf are not equivalent to rig counts anywhere else in the country. Just as an example, if you do this on a comparable basis to EURs, this rig count would be equal to about 150-200 rigs in the Permian. If you look at it on an EUR basis. About 375 rigs last week in the Permian, horizontal rigs actively working out there.
You've got 14 here in the Gulf, it's certainly not an apples to apples comparison when you look at rig counts here. This is a very interesting activity that's underway, and for us, incredibly interesting because if you look at those rigs, they are all associated right on top of our assets. Certainly something that we like to see. The projects that I've talked about, the big projects, those are obviously out into the future, but we are seeing a lot of tieback activity today from Kosmos and other producers out there that are very active, and they're very interested in those tiebacks because for them, it reduces their capital investment. They can get those projects online very quickly, and they can get a very quick return of their investment on those wells drilled.
That's why you're seeing a lot of activity right on top of our assets where we have latent capacity. We can quickly bring those very rich reserves of gas in. I'd like to point that out as well. Every one of these associated gas opportunities that we're seeing out here, these are very rich NGL-laden gas streams that are coming ashore to our processing facilities that we can then process ashore from our existing asset base. Great opportunities for us coming here in the Gulf of Mexico. Just wanted to give you a quick perspective on the three major projects that we're chasing here, and there are some recurring themes that I'll just point out here. Existing asset base, taking advantage of here across all three of these opportunities. Great customer base, Total, Chevron, Shell are the primary customers here that we're working with.
We have a great relationship, worked very well with them in the Gulf of Mexico for a long time. Our risk is mitigated where we have to deploy capital. We have a known rate of return on that already embedded in these contracts. Where we do have to invest capital for any of these, we'll get a known rate of return on that. Our risk is mitigated in that regard. Incredibly large reserves here, if you look at those numbers, and I'll give you a perspective on that. Today, with our current gathering volumes that we're bringing into our system, we have about a 30% market share on gas today at about a 10% market share on oil gathering in the Gulf of Mexico today.
When these projects come online at their peak, it will increase our oil gathering by 150% in the Gulf and our gas gathering by about 100% from what we're doing today. I can assure you, these are very exciting opportunities for us, and we expect these, as you can see, mostly to come online in the 2023 timeframe. Before that, we're going to have a lot of these other tieback opportunities coming on as well. It will continue to show growth in our Gulf of Mexico assets. That really wraps up my portion of the presentation. I'm looking forward to your questions in Q&A. I can assure you, our team is very focused on creating and driving toward an excellent culture of operational excellence within our business. We have done that. Our teams are very committed to that.
We're very excited about the opportunities that we have in front of us in the Williams organization. I am pleased to say we're going to give you a break for about 15 minutes now and come back, and you'll hear from Chad and John to close out our presentation. Thank you.
[Break]
Hi, everybody. If we could get back to our seats, we're going to continue the program here. I'd like to welcome Chad Zamarin, Senior Vice President of Corporate Strategic Development. If everyone could make it back to their seats, that'd be great. Thank you.
I think we'll get started. Well, good morning. Thanks for being here. I'm really excited to share a look into our strategy process. Give you a bit of an inside look into how we think about our company and the strategies that we look to deploy to continue our growth. Hopefully, there are a few key takeaways that you'll leave here with today from the material that I'll go through. One is that our strategy is based on solid fundamentals. I think you heard that loud and clear from Alan's presentation.
Michael talked about the fact that the fundamentals really do support our vision and strategic direction. Two, we are constantly monitoring those fundamentals and constantly sharpening our strategy to adapt to potential changes, so that we are well-prepared to deliver on our commitments. Michael talked about how we tune our capital program, how we continue to stay ahead of the activity that we see around us. I'll also talk a little bit about how we are constantly looking at making sure that our assets and our portfolio are well-positioned in the event of multiple different scenarios from a macro fundamental perspective. Hopefully, you take away also that our platform is very large. Scale helps, scale matters. We have a diversity that provides a tremendous amount of optionality and stability, and we have many levers to pull to achieve our strategic goals and objectives.
Finally, we are continually focused on optimizing our platform in order to keep our footprint relevant, and equally importantly, in order to capture value and stimulate outside return. I'll talk a little bit about some of these examples and put a little bit more context around that concept. To be clear, we recognize that markets evolve and that they cycle. We currently do find ourselves in a more challenging environment, but I think our results show, and we believe that we are the very best positioned natural gas platform in the space. Our opportunities, coupled with an incredibly healthy, solid, and resilient base business, we think provides us with an opportunity to not only flourish in times of upswing, but in order to take advantage and better position ourselves than others in times of downswing.
Keep in mind that we closely monitor the fundamentals, we adapt our strategy to remain ahead of the curve, we leverage our unique and diverse platform, and we continuously look to optimize our portfolio to achieve results through various market cycles. Even though the news doesn't always highlight our story, as I sat and watched Alan's presentation, it continues to, I think you hear from us, confound us a bit that we sometimes forget that the U.S. is still experiencing an energy renaissance, and in large part driven by the success of natural gas. Energy production is up dramatically, while costs to consumers are down, and emissions continue to fall. I mean, that is a pretty amazing dynamic, and in large part, thanks to natural gas.
That's the type of trend that needs to continue in the U.S., and as you've heard, will continue to accelerate around the world. Keep in mind that not long ago, we were increasingly dependent upon foreign sources of energy, including natural gas. I came from a company that, at one time, was planning to import natural gas and is now exporting natural gas from the U.S. Today, we're exporting almost eight BCF a day of natural gas, and that volume continues to ramp rapidly. That's almost equivalent to not just the LNG demand, but the total gas demand on a daily basis of Europe's largest gas consumer, Germany. It's more than the daily demand of France, Spain, and Portugal combined. It's a remarkable amount of gas that we're sending to consumers around the world.
Our infrastructure, the Williams infrastructure, is the largest delivery system enabling these growing exports from the U.S. As we think about our position, the good news for us is that we're ideally situated to serve the growing demand, and we have a unique footprint of scale, geography, and flexibility. We have assets of scale in every important gas supply basin in the U.S., and our gas transmission assets, as you've heard, are ideally located to move natural gas around the U.S. and for LNG exports to serve the rest of the world. There are few long-haul pipelines that hug the coast like ours, and none have the scale and flexibility. I think it's always helpful to pause and think about the U.S. and the remarkable infrastructure that we benefit from here.
No other place in the world can connect LNG export facilities into a grid like we do. In every other part of the world, in order to build an export facility, you typically build that facility on top of a reserve or a reservoir. Here in the United States, we're tapping into a network of infrastructure that's connected to a supply diversity that is unmatched anywhere in the world. We are very focused, as I hope you've heard, on making sure that our infrastructure is a key network that connects that supply and delivers to that demand. As we look to the next 10 years, we will benefit from the fact that demand for natural gas will continue to grow. You heard from Alan that we have strong conviction around gas demand growth.
Although we often hear risks about gas demand, it's too often that we forget that base load in the United States is absolutely rock solid. The only debate really to be had is the pace of demand growth over the next 10 years. We see a few key drivers, we'll talk about those here in a second, with demand continuing to be led by LNG exports, representing about half of what we believe the demand growth will be over the next 10 years. Still, strong demand growth from virtually every other sector, within the value chain. Natural gas, as you've heard, is abundant, low-cost, and critical to achieving our clean energy goals, we think we're well-positioned to participate in this growth.
From a supply perspective, you see here on the slide that we continue to see the power of a diverse supply geography, Most of the growth that we believe comes over the next 10 years will come from three key basins, the Permian, the Haynesville, and the Northeast. A forecast of over 30 Bcf a day of supply growth from these three basins alone over the next 10 years. I'll talk a little bit more about how that influences our strategy. You see here on the slide that, when we think about the Permian, the Haynesville, and the Northeast, the one thing we know for certain is that no one knows for certain what exactly will happen over the next 10 years. We are planning to be prepared for multiple potential scenarios.
When you look at the Permian on the left-hand part of the slide, as we know, the Permian is driven by oil economics, but it's important to note that the Permian is also constrained from a takeaway perspective. Only one new major pipeline has been constructed from the Permian, bringing total takeaway capacity. The chart on the left is takeaway capacity. The blue is in-service pipeline takeaway capacity from the Permian. The green is capacity that's been announced as having reached a final investment decision. You see that there's approximately 11 Bcf a day of takeaway capacity currently from the Permian. For the most part, that capacity is fairly highly utilized. You see that there have been two additional pipelines that have been sanctioned, and that are being developed.
That will add only an incremental four Bcf a day of capacity, and we think that capacity comes online sometime in the next couple of years. As you can see, in order to keep the Permian growing, the Permian will be dependent upon an ongoing installation of takeaway capacity. In order to exceed that 15 Bcf a day, the pace of the additional capacity is something that we'll keep a very close eye on. As expected, coming from the Permian, this capacity is, for the most part, pipeline capacity that needs to be built over a very long distance, in very large diameter. Even though construction is in Texas, I can tell you that it is still challenging to build a 400-mile large-diameter pipeline. We've already seen announced delays for the projects that have been brought to FID.
We expect to see additional delays, upward pressure on costs, and downward pressure on project returns. We've talked to many of you about our involvement in the Permian. From our perspective, the current market economics for new greenfield pipelines from the Permian still don't represent a very attractive risk-adjusted return, especially against the more attractive opportunities that we see along our mainline assets. That said, we keep a very close eye on the Permian. As Permian supply migrates to the Gulf Coast, we will be expanding and reconfiguring our footprint and our Transco mainline in order to deliver gas to key demand markets. We'll continue to evaluate opportunities to participate in the basin and potentially in projects that connect the basin to our Transco mainline, if and when those economics become attractive.
I can tell you that you should expect to see development and expansion of our mainline system in South Texas to ensure that we can move gas that's migrating from the Permian to the Gulf Coast to markets that our mainline system serves. Under any scenario, we expect to benefit from supplies that are moving out of the Permian. As discussed, the Northeast, on the other hand, will continue to be the largest supply basin in the United States for natural gas. Its pace of growth will be based, unlike the Permian, on both rich and dry gas economics. The interesting thing to note about the Northeast now, if you look at the chart, this chart shows in the orange bars the projected supply growth over the next 10 years, and the blue line is the available takeaway capacity from the Northeast.
The Northeast has now over 10 Bcf a day of excess pipeline takeaway capacity, which is important to note. As supply continues to grow in the Northeast, we will continue to adapt and expand the receipt and deliverability of our infrastructure to move gas in even more flexible ways. As I think you can tell from this chart, the Northeast will have the most flexible potential to flex with the market as demand swings due to its scale and due to the availability of excess takeaway capacity. Finally, the third really important basin as far as supply growth over the next 10 years, the Haynesville. When you think about the Haynesville, we see the Permian as being oil-price sensitive. We see the Northeast as having a nice optionality between rich gas and dry gas. The Haynesville is almost exclusively dependent on dry gas economics.
Perhaps surprisingly, the Haynesville is also constrained by takeaway. I think that we oftentimes think of the Haynesville as being very geographically close to demand markets, but the Haynesville takeaway capacity was in large part developed in order to move gas to markets outside of the Gulf Coast and to the East and to the Northeast. Traditional gas flows from the Haynesville to markets other than those growing markets that we see over the next 10 years. We will continue to see the need for infrastructure in order to move incremental gas growth from the Haynesville, whereas traditional gas flows would move into markets where they would compete with gas coming from the Northeast and other supply areas. The good news is, though, that we have a super attractive footprint in the Haynesville.
We have a system of large scale in truly the core of the core Haynesville. We're focused on connecting our system and other supplies that are going to move out of the Haynesville to our infrastructure along the Gulf Coast and our Transco footprint. Although we hear a lot of questions about supply growth from the Northeast, it's important to know that we're well-equipped to serve the gas demand needs under multiple scenarios. We keep an eye on where we think that gas will come from. We're confident in our ability to deliver under virtually any scenario as we move forward. With that fundamental backdrop, I'll provide a brief window into our strategy process. The first thing I hope that you recognize is that we have a very comprehensive strategy process.
We have a formal annual process in close collaboration with our board of directors and an ongoing focus in fine-tuning of our strategy. It's not a trivial exercise. We dedicate a lot of time and resources to our efforts, and we really focus on making sure our strategy is thoughtful, disciplined, and at the same time, flexible and dynamic. Through this process, we assess fundamentals. You've seen, I think, that we spend a lot of time on trying to understand the market around us, but I think we also recognize that we don't know all the answers, and so we make sure that we are prepared to adapt to changes as they present themselves. We identify strategies. Michael talked a lot about our core businesses. We identify strategies to leverage our core businesses based on the framework of those fundamentals around us.
We look for strategic options and adjacencies and develop plans for portfolio optimization and positioning. I'll talk a bit more about that. You shouldn't be surprised that most of our efforts are focused on where we believe we have unique advantages, and we can capture unique returns based on those advantages. Finally, this work is focused on validating a long-term financial plan that is designed to meet our growth goals as well as our leverage metric goals. The goal of our process is to position us for success, as you've heard, under a variety of scenarios, target an investment strategy where we have unique advantages and can capture higher investment returns, and optimize our portfolio to improve asset positioning. I'll talk a bit about the idea of recycling capital to stimulate long-term growth. Here, I've provided a snapshot of our long-range financial planning.
John Chandler's going to go through more detail, we'll expand. Important to note that I think past performance demonstrates an ability to achieve attractive growth. During the 3-year period of 2016 through 2018, we invested approximately $7.5 billion of growth capital and delivered a 12% return on invested capital, growing our EBITDA by approximately $900 million. This is an impressive growth rate that we believe is achievable over the long run. In fact, during that same time period, we sold over $4.6 billion in assets at very attractive multiples of EBITDA, and we see an even greater performance, not entirely represented by these numbers, as we sold those assets and EBITDA and used those proceeds to de-lever. I would tell you that our investment platform is incredibly powerful.
We have a number of levers that we can pull, and we have confidence in our ability to continue a steady and predictable growth rate. Not only do we look at past performance as a potential indicator for how we can grow the business over time, but each year, we also do a bottoms-up analysis. We look at every part of our business, every asset, the potential of each of those assets, and the potential for us to grow, as well as stimulate outsized returns through portfolio optimization, and that, again, gives us confidence that we can deliver on our long-term growth goals. The following slides summarize the unique portfolio that we operate, with a focus on strategic positioning of our core assets. I won't go through each in detail since Michael hit many of the key points, but I will touch on some strategic highlights.
I hope that this serves as more or less a very high-level, kind of six-page strategy book of how we think about our business. Again, I'll just hit on a few of the key highlights. Alan talked about the really incredible scale and diversity that we have, the very wide moats that we have that we benefit from. We have attractive and increasing vertical integration. I'll talk a little bit more about that, but Michael also touched on how we've connected our west position all the way to the Gulf Coast from an NGL integration perspective. Our platform provides diversity and stability through various market cycles, and I think you've seen that through the materials that have already been shared.
As discussed, our transmission assets are the largest in the nation, with a header capability that is unique and with an ability to receive and deliver, as Michael said, 100 Bcf a day of natural gas in increasingly flexible ways. Michael talked about it. Just to reiterate, that means that we can take gas in. You saw Transco having 18 Bcf a day of transport capacity, and growing. In fact, every day, we're moving gas in and off our system in orders of multitude in excess of that. We can receive gas and deliver gas dynamically across our system, the flows across our system change based on the market needs. There is no other system in the country that can do it at such a level of flexibility as we can.
From an NGL value chain integration, an area where we've spent quite a bit of time over the last 18 months since we spoke last. Our integration is increasing and is impressive. Our gathering and processing footprint will soon be physically integrated, as you heard, all the way from the Rockies to the Gulf Coast. Our Northeast footprint has been significantly enhanced through our integration of UEO and OVM through a transaction that I'll talk a little bit more about in a minute. We've effectively created an NGL super system in the Northeast through that integration. I'll pause for a moment on our West G&P assets. I think these are assets that sometimes get a little bit undeservingly ignored. This is an incredibly attractive position that we have, that we benefit from, and it's unique with diverse and very high cash flows.
The West G&P position is comprised of 10 franchises generating approximately $1 billion of annual EBITDA with very large free cash flow. These are the types of high-quality midstream assets that the private market finds attractive. Assets that provide scale and stability, high cash flows and attractive yield, and a strong operator investing for long-term value. We are not a build-and-flip operator. We don't operate single-producer systems. These are very attractive assets, very mature assets with high levels of contracted cash flows, with high levels of mature PDPs that investors find very attractive. We continue to see strong interest from potential partners looking to invest in platform assets in the U.S. along a strong and reputable operator. This is one area where I think we would likely see the public markets putting a lower multiple on these assets into some of the parts of our assets.
I think our transactions and other transactions have shown that for high-quality assets, there is a high degree of interest in investing at much higher multiples than the public market seems to want to give us credit for. We'll talk a little bit more about the opportunity to continue to optimize our portfolio and take advantage of that dislocation in value that we see, in particular, on our G&P assets. The Northeast has been talked about in detail, so I won't go through much more. Just to reemphasize that our scale and diversity is a huge advantage. We are the largest position in the Northeast, and that will allow us to continue to benefit from growth. We've got a great opportunity for ongoing consolidation and integration, even just within the assets that we own and operate in the basin.
Finally, on the offshore, Michael talked about the offshore position, very large scale, ideally positioned. I thought, really powerful slide to see the rig activity and the size and scale of the opportunity just within our footprint. We're seeing more activity in and around our footprint than we've seen in a very long time, and we think that will be beneficial over the long run. Just to kind of wrap on the assets that we operate. As you can see, we have an incredibly unique portfolio, and our assets are incredibly valuable. Unfortunately, though, as I've mentioned, the public market has continued to underestimate the value of high-quality midstream assets. Shown here are examples of transactions that demonstrate the value of our midstream assets.
As you can see from the first four transactions in the blue, we have captured very attractive valuations for assets that we have in our portfolio, and we strongly believe that these aren't outliers. In fact, many would likely characterize these assets as representative of the lower tier within our portfolio. Yet we continue to see transactions that place high value on quality midstream. At the far left is our Four Corners transaction, which sold for over $1.1 billion on approximately 14x multiple to a private equity-backed operator. Next, our Gulf Coast Purity pipes were sold to a private equity operator for a very attractive valuation. Also shown is the investment made by CPPIB, which I'll talk a little bit more about in a second, into our Northeast G&P platform. Finally, the sale of our Powder River Jackalope system, which was sold to Crestwood.
However, if you look at the funding of that transaction, it was in large part funded through a consortium of private equity investors. The remaining examples on this slide are several recent transactions at, again, very high multiples, and I would argue that in many cases, these assets are inferior to our large-scale, diverse positions. What this means is that, again, not all assets are equal, and our large-scale mature positions provide very attractive value to investors. While the public market seems to miss this differentiation, we will continue to take advantage of these opportunities. Finally, as discussed, a core focus of our strategy is a focus on portfolio optimization. I thought I'd close with sharing a few thoughts on how optimization has and will continue to enable us to capture value and stimulate growth over the long term. Our process is pretty straightforward for portfolio optimization.
We anticipate emerging opportunities and position our assets, capability, and resources in the right place to capture value. We identify areas of strength where consolidation integration offers unique returns only available to Williams. We position underutilized or less strategic assets for growth or explore opportunities for monetization. We've been working hard to attract capital partners that position us to grab opportunities as they present and structure transactions in a way that is creative and value-adding. I'll share a few examples of recent transactions that provide some insight, and hopefully give a window into the types of ongoing opportunities that we'll continue to evaluate and pursue. The first transaction is our Four Corners. The sale of our legacy Four Corners assets for over $1.1 billion, and the acquisition of our Rocky Mountain Midstream position.
I think this is a good example of the recycling of capital from a low-growth asset into a high-growth opportunity. This trade was made even more valuable to Williams due to the adjacency and ability to integrate with our existing NGL infrastructure. You heard from Michael that, combined with our existing West gathering and processing footprint, this project helped enable the expansion of our downstream NGL network and will soon be connected all the way from the Rockies to Mount Belvieu. We will look to capture value at each point of the value chain as we move those NGLs from the Rockies to the Gulf Coast, including all the way through fractionation. On the other hand, we acquired the Rocky Mountain position alongside KKR, a strong and like-minded financial partner. To acquire that position, we've invested significantly less than the proceeds from the Four Corners sale.
As you can see here on the chart, we are growing the Rocky Mountain Midstream earnings rapidly, and we will soon exceed the earnings of the legacy Four Corners system. We see highly visible growth continuing in our DJ position for a long time to come. That's even without taking into consideration the increased margin that we will capture on a significant amount of NGLs that will be generated out of that position. In the Permian, we contributed our Delaware Basin assets into the adjacent Brazos Midstream system in exchange for a 15% equity interest and a dedication of residue gas from that Brazos system. The combined system is really an impressive force to be reckoned with. Our legacy assets brought very attractive acreage dedication, but our position lacked existing processing capacity, so we had a competitive disadvantage as a standalone legacy operator.
Upon combination with Brazos, we create a system of scale, both with gathering and processing, and one of the best and most diverse customer profiles in the basin. Our share of the combined platform is already exceeding the earnings performance of our legacy position. This transaction was made without even contributing cash. This was a non-cash contribution of our existing assets into the Brazos Midstream platform. This is not even taking into account the significant residue volumes in the Permian, which positions us to lever into additional opportunities in the future. One final example is our partnership with the Canada Pension Plan Investment Board, or CPPIB. This transaction includes the investment by CPPIB of over $1.3 billion into our Northeast platform.
As part of the transaction, we acquired the controlling interest in Utica East Ohio, and combined that asset with our wholly owned Ohio Valley Midstream system, creating a much stronger position in the Northeast. The integrated assets create a Southwest Marcellus and Utica super system. With a well-capitalized partner in CPPIB and our expansive footprint in the Northeast, we are well-positioned to continue to leverage this platform for ongoing growth and value creation. We continue to see additional opportunities similar to this, not only in the Northeast, but truly across our entire footprint. Our assets of scale and high quality in nearly every basin make us a very attractive potential partner and investment opportunity for private equity money. In summary, the transactions that I've highlighted are just a few notable examples of how we are continuously working the levers of our platform.
These transactions improve our strategic positioning, create additional growth opportunities, while at the same time improve our balance sheet. That's the recipe that we will continue to look for as we move forward with portfolio optimization. We believe there are many of those left to capture. In summary, we've got a great platform to leverage. Our long-term planning process is robust and deliberate. We have a foundation of rock-solid core assets, and we will continue to optimize our portfolio to increase value and stimulate long-term growth. With that, I'd like to hand the microphone to my favorite CFO, John Chandler. Thank you.
All right. Thanks, Chad. Good morning. You've heard, obviously, that we believe in long-term demand growth for natural gas. That's supported by strong fundamentals. You've seen our quality assets. You've seen our solid execution. Hopefully, I can bring this all home in a discussion of our really strong financial performance and the results that we've seen there. First, I want to start. At our Analyst Day in 2018, so this is 19 months ago, we presented four key pillars of who we are as a company. We said, first, that we want to be a company that delivers strong execution. We want to be a company whose earnings are built on a stable foundation. We want to be a company who's well-managed and managed conservatively, maintaining significant dividend coverage that supports our growth while also allowing for improved leverage metrics.
Finally, that we want to be a company that will focus on growing its Vantage business while also improving its return on capital employed. As I stand here today, I'm proud to say that we've delivered on every front on those pillars, and we continue that same commitment to our investors going forward. On the execution front, since 2017, we expanded Transco's capacity by 17%, all backed by long-term firm-committed capacity. Between 2018 and at the end of this year, we will see Northeast gathering volumes grow by 14%, and that's on top of 8% gathering volume growth that occurred between 2017 and 2018. We have met or exceeded the street consensus for EBITDA each of the last 15 quarters, and this year, we're on track to achieve our 2019 financial metrics.
On the ever-important leverage metric, we have done substantially better than we had originally projected. On the stable foundation front, we've stayed committed to our natural gas and NGL-centric strategy, where I believe we are the best and one of the most efficient operators that will give us a competitive advantage over the long term. We have irreplaceable assets that handle 30% of the U.S. natural gas. We've maintained a very high percentage of fee-based business, with only 2% of our gross margin coming from direct commodity price exposure. Despite a weak commodity environment, we've delivered EBITDA growth each year, you'll see in 2020, we'll do that once again. On the conservative side, at our Analyst Day in May of 2018, we were guiding that our 2019 leverage ratio, we're hoping would be inside 4.75 times.
As I stand here today, we're inside 4.5 times, and our guidance for 2020 is that we'll end closer to 4.4 times as we move ever closer to our goal of hitting that 4.2 times debt-to-EBITDA leverage ratio. Those steps have come not only due to capital discipline, but they've also been due to intentionally pursuing asset sales opportunities to help fund our growth capital and to help obviously delever. We are proud to say that when including cash raised through asset sales and given our excess cash flow and our expansion capital spending we're projecting this year, we will completely fund our dividends and all capital with cash on hand with no need for debt or equity in 2019.
As we look into 2020, even without the aid of asset sales, we will be free cash flow positive, completely paying for growth in our dividends, also paying for all capital without any need for debt or equity. Finally, on the growth side, we continue to grow Transco, which is the nation's largest and fastest-growing pipeline, with a continuing slate of very attractive growth projects. You heard that from Michael. We continue to grow our gathering assets in the Northeast, where we continue to be the largest natural gas gatherer in the Northeast. We gather one-third of the gas in the Northeast.
In addition, we are partnering with private capital to both grow our position in the Northeast and where possible, in the West. We continue to see significant emerging growth opportunities in the Deepwater, where we'll begin to see additional EBITDA, meaningful additional EBITDA in the next three to four years from Deepwater activity. Finally, we've developed an integrated platform now that allows us to bring our Rockies' NGL barrels down through our jointly owned Overland Pass Pipeline system, across our Bluestem pipeline, which is currently being developed, and ultimately through a joint interest we have in a frac with Targa. Bottom line, we are delivering, and we will continue to do so into the future. These aren't just words. The numbers don't lie. In fact, if you look at all of the key financial metrics for the company, we are seeing significant improvements.
On the cash generation side, our cash from operations has grown at a 9.4% CAGR since 2017. Similarly, our distributable cash flow has grown at a 9.6% CAGR since 2017. Actually, that number could come in a bit higher, depending on the outcome of our maintenance capital spending for the year, which is trending lower than we had planned. This has helped us increase our dividends at a 12.5% CAGR, while also de-leveraging as we move towards our 4.2 times debt-to-EBITDA goal. On the earnings side, our adjusted EBITDA has grown at a CAGR of 5%, and that's even after selling $1.3 billion assets in 2018, mostly from our Four Corners gathering assets, and another $485 million in assets earlier this year from our Powder River Basin assets.
Our adjusted earnings per share has grown at a 22.8% CAGR, due largely to the growth in adjusted EBITDA, with the majority of that growth in EBITDA falling to the bottom line because, again, we funded that growth largely through cash from asset sales and also through excess cash flow to fund capital. Not a lot of new interest expense and certainly not a lot of new depreciation. On the efficiency side, our operating margin percentage, which is a measure of how much revenue finds its way to the EBITDA line, has increased substantially, going from 62%-67%. That's a significant improvement in a short period of time. We'll discuss this more in a moment, but we've taken additional cost reduction efforts in 2020 that will help us further move that forward in the future.
Finally, on the financial discipline side, we have brought our leverage down under four and a half times on the back of both solid EBITDA growth and also through selective asset sales. Again, our words are being backed by actions, and our actions are evidenced by our financial results. I do want to spend a moment talking about our return on capital invested. In 2018, we introduced for our management team, as part of our long-term incentive compensation, a measure that measures 3-year improvement in our return on capital employed. We also had that in our 2019 performance shares, and I suspect that will be part of our 2020 performance shares as well. Obviously, to meet this growth in return on capital employed metric, we have to invest wisely, and we also need to conservatively manage our business. Again, the proof is in the numbers.
If you look at our return on capital invested, we are seeing solid returns. On this slide, we've plotted the increase in EBITDA from our retained assets. In other words, we've excluded our assets that we've sold from both the beginning and the ending number. If you look at a three-year growth in EBITDA from our retained assets, we've grown the EBITDA by $900 million between 2016 and 2019. We divided that by our capital investment over a three-year period, 2016 to 2018, where we've invested $7.5 billion in capital, and that produces a 12% return. Obviously, I've excluded 2019 capital. Returns from that will show up in 2020 and beyond. Again, we've produced a very solid three-year growth in EBITDA over a three-year investment cycle of 12%, and that excludes or doesn't even take into effect that we've sold assets at very attractive multiples.
In fact, if you blend in the $4.6 billion in assets that we've sold and look at the EBITDA growth, including the assets we had at the beginning of the period and don't have at the end of the period, our return jumps to 19%. Obviously, this growth and this attractive Return on our investments have helped us to improve our Return on Capital Employed over a three-year period CAGR of 10% since 2016. We're investing wisely. As we look into 2020 and beyond, we want you to know the core financial principles that are important to us as a management team and also to our board. The first is we want to see continued improvement in our Return on Capital Employed year-over-year. Again, our management's long-term compensation is tied to that, and our board is incredibly focused on that, as well as the management team.
We want to continue moving our leverage towards 4.2 times or below with a focus on solid BBB, Baa2 investment-grade ratings with the rating agencies. We want to return capital to our shareholders, this will be through dividend growth, and we hope, depending on the pace at which we can bring our leverage down, also through share buybacks. We want to continue to focus on improving our operating margin %. We have made great progress of leveraging our operating structure and becoming an efficient operator. We plan to continue to scale the business without adding much new cost, we plan to leverage our cost efficiencies into continued opportunities with private equity capital in JV structures around our existing assets. Finally, we want to deliver long-term EBITDA and cash flow growth in the 5%-7% range.
We think these are the fundamental building blocks to delivering superior financial performance and a superior return to our shareholders. Now I want to provide some insight into our EBITDA guidance for 2019 and for the year-end 2020. First of all, I want to say we gave guidance for 2019 back in May of 2018. At that time, the midpoint was $5 billion. We remain on target to come in right around that number today. There have been obviously some very big changes since May of 2018. We, of course, had a big shift down in natural gas and NGL prices, resulting in a reduction in rig activity towards the end of this year. We bought the UEO system in the Northeast. We also sold our Powder River assets in the West.
We bought the Rocky Mountain Midstream assets in the West, but we also sold our Four Corners assets in the West. Of course, we've seen a pretty big decline in commodity margins. Yet, here we are today, still right on our original guidance. I think a key message here is that we have a big, diverse system. You saw that in some of the balance slides showing the stability of our EBITDA stream. This gives us a lot of opportunities to respond to changing market conditions, and is certainly, again, one of the factors that's contributed to our long-term stability and predictability of our EBITDA. As we look between 2018 and 2019, again, we're seeing our EBITDA grow by about 8%. This is a result of strong growth in the Northeast.
We had mentioned the Northeast volumes have grown by 14% this year on the backs of really strong growth in Susquehanna and the Bradford supply hub. We've seen incremental revenues from successfully bringing on our Atlantic Sunrise project in October of 2018, as well as contributions from our Gulf Connector pipeline. We successfully accomplished a settlement in principle with our shippers, resulting in rate increases on our Transco system, and I think there are many people who were predicting rate declines. We've had higher revenues in key basins in the West. Our DJ Basin assets are growing quickly. More significantly, our Eagle Ford and Haynesville assets have grown significantly, where between those two basins, they both have grown in 2019 at about somewhere between 9%-10% year-over-year.
This growth is despite losing $100 million in EBITDA from asset sales and also having about $100 million less in margin from commodity margins. As we look from 2019 into 2020, we are projecting at the midpoint EBITDA of $5.1 billion. That's a $100 million increase over 2019. That's a 2% increase, or if you drop back to 2018, that's a 5% compounded annual increase. Importantly, I do want to point out that 2020 is being negatively impacted by about $100 million due to non-cash step down and some deferred revenue amortizations. Obviously, if you factor that out, just the year-over-year growth goes from 2% to 4%. If you look at the $100 million growth in EBITDA from 2019 to 2020, the biggest increase obviously is the growth coming out of the Northeast.
Again, we expect the Northeast to grow from $1.3 billion to $1.4 billion between 2019 and 2020 on the back of growth in volumes, albeit not as significant as we saw this year. Otherwise, we have increases along our Transco system and in some of our deep water assets that are being offset by this decline in non-cash deferred revenue. Transco is seeing the benefit of full year in service of our Rivervale project, along with incremental revenues from bringing online our Transco Gateway project, and from incremental EBITDA reflective of a full year of our settlement in principle with our shippers. Our deep water assets are seeing an increase from a full year in service of our Norphlet Pipeline, which we acquired mid-year this year from Shell.
Our gathering systems in the West are seeing incremental EBITDA from continued ramp up of the DJ Basin assets and our Eagle Ford assets as a result of a rate renegotiation we had with our customer. Offsetting this is lower EBITDA in the Haynesville based upon expectations of lower drilling activity in that basin. Finally, in order to maintain the improvement we have achieved in our operating margin percentage over the last several years, we have completed a plan that will deliver $75 million in cost savings in 2020, and the benefit of this cost savings is somewhat muted by just normal inflation or increases in cost. Again, all these positives are largely offset by $100 million decline in non-cash deferred revenue. Now, of course, there are some upsides to our 2020 numbers.
First of all, if commodity margins return to 2018 levels, we would see commodity margin upside of around $100 million. Second, I would say this. Back in the third quarter of 2018 on our earnings call, we gave guidance of a 15% compounded annual growth rate of volumes in the Northeast from 2018 through 2021, and of course, we've stepped that down over the year. At that time, so in the third quarter of last year, our projections for EBITDA in the Northeast were between $1.6 billion to $1.7 billion in the Northeast. We sit here today with guidance of $1.4 billion. Of course, gas prices have come down pretty significantly over the last year, around 8%. Of course, NGL margins have come down even more. It's hard to know exactly how quickly that price is going to respond and come back. We believe demand will continue to grow.
We believe there will be a price signal to the producers, and they will come back, and we believe that EBITDA will find its way back into our system. That's not in our projections, though. The final thing I would say, obviously, our commercial teams are very active in trying to attract incremental volumes to our latent capacity on our gathering systems. In many cases, there are reserves in very close proximity to our existing systems that require very little to no capital. We believe we will have some success on this front in 2020. One area would be in the Haynesville, where we are very active today talking to other producers in the area. As I mentioned earlier, our EBITDA is both anchored by very substantial capacity on high-quality transmission pipelines, and it's also diversified among many basins.
Now, we had mentioned in previous calls we were going to provide some more detail, and while we definitely do not intend to continue to provide this level of EBITDA detail going forward, we've heard from a number of our investors that it would be very helpful to recalibrate their models, and we hope this level of detail will allow that to happen. Some things I hope you can take away from this slide. First of all, on the left, you can see that because of the diversity of our earnings stream, we've had very stable to increasing EBITDA from our continuing assets. In addition, even including the assets that have been sold, which you can't really see that on this slide, but it's a small gray sliver at the top.
It's continued to be stable to growing EBITDA, even with asset sales. On the right, hopefully you can take away from this that we have, again, a substantial portion of our EBITDA anchored to very high-quality transmission pipelines, where we are paid for firm capacity. No volatility. It's not volume driven. We get paid for firm capacity. Second, I hope you can take from the right side of this slide that our EBITDA from our gathering assets are diverse. Meaning pressure in any one basin is not that consequential to our overall EBITDA. Our exposure to multiple basins allows us numerous growth opportunities. Finally, I hope that you take away from this slide that our Susquehanna supply hub gathering system has quickly grown to be one of our largest gathering systems based on EBITDA contribution, and that's backed in part by our high-quality producer Cabot.
Further adding to the stability of our EBITDA is the fact that our business remains substantially fee-based. I mentioned this at the beginning. 98% of our gross margin in 2020 is projected to come from fee-based revenues, with only 2% coming from direct commodity price-exposed activities. Of the 98% of our fee-based gross margin, 44% comes from natural gas and liquids transportation, primarily Transco, Northwest Pipeline, and Gulfstream. 6% comes from our deep water gathering and transmission assets, 48% comes from the Northeast and West gathering and processing fee-based revenues. Looking into that 48%, 11% of that comes from minimum volume commitments. 10% comes from cost of service agreements, which are protected revenues too. Finally, 27% is subject to volume exposure. Again, if you recall the previous slide, that's across many different basins.
Now, in response to the pullback in drilling activity, we've also responded by pulling back our expansion capital. We've been very responsible on that front. We're focusing more of our spending on our transmission pipelines. In 2018, we spent $3.6 billion in growth capital, with 51% of that on our transmission systems. In 2019, we had projected we'll spend at the midpoint $2.4 billion, but I can tell you with the latest forecast, we're expecting around $2.2 billion of expansion capital in 2019. With that, 47% was along our transmission systems. Then finally in 2020, we are projecting we'll spend $1.2 billion in expansion capital, with 61% of that being on transmission assets. Of that $1.2 billion of expansion spending, our gathering investments are only projected to be about $100 million in the West and $300 million in the Northeast.
In both cases, that's substantially less than we've spent in prior years. It's in direct response to the lower drilling activity by our producers. As a result, again, of this capital discipline and our significant free cash flow, we expect to continue to improve the leverage ratio into 2020 while providing dividend growth and funding, again, all of our capital needs without the need for debt or equity. This page is something I'm very proud of. In 2018, we paid for two-thirds of our expansion capital with excess cash flow after dividends and from cash from asset sales. Looking into 2019, with $2.2 billion in spending on expansion capital, we will entirely pay for our expansion capital with excess cash flow after dividends and from asset sales with no need for any incremental debt.
Then as we look into 2020, again, using the midpoint of guidance of $1.2 billion of expansion spending, we will be free cash flow positive after dividend growth and dividends and after all capital spending. Any cash that we would raise through additional asset sales will go through advanced de-leveraging. One thing that often gets overlooked because we focus so much on EBITDA is the opportunity for reductions in interest costs and cash flows benefits from that. In 2020, we have $2.1 billion of debt that's maturing, then we have another $900 million of debt maturing in 2021. If we were to refinance that debt today at 10-year rates that are available to us today, which are around 3.5%, we would see a $49 million annual savings in interest cost.
I will tell you, we continue to monitor the markets very closely. We do find current rates very attractive. We remain sensitive to the fact that based on our current expansion capital spending projections and ability to actually generate more cash than we're spending in 2020, we will be able to pay down some of that maturing debt with cash. In addition, we are mindful of potential future asset sales and do not want to get into a situation where we unnecessarily refinance maturing debt when we might have some cash on hand to retire that. Just looking at our guidance, I've already addressed many of these points. Our 2019 guidance is the same guidance we provided on our previous earnings call, other than suggesting we will come in below the low end of guidance on our growth CapEx.
As we look into 2020, our midpoint for net income is $1.35 billion. Our midpoint for 2020 adjusted EPS is $1.08 per share, which is 14% higher than 2019. Our midpoint for 2020 adjusted EBITDA again is $5.1 billion, which is 2% increase over 2019 or 4% if you adjust out the deferred revenue amortizations. Our midpoint for 2020 distributable cash flow is $3.25 billion, which is a 5% increase in DCF versus 2019, with a similar 5% increase in DCF per share versus 2019. Our dividends are expected to grow at 5% in 2020, which is consistent with the growth in our DCF and our DCF per share. Our 2020 growth CapEx again is expected to be at the midpoint, $1.2 billion. With our leverage ratio at the end of 2020 of 4.4 times.
I do want to give you a view of how compelling we believe the investment opportunity is in Williams. If you look across the spectrum of investment opportunities in the S&P 500, Williams is truly unique. In the S&P 500, there's only 11 companies with a dividend yield that's greater than 6%. Obviously, we're one of them. Of those, only five companies have a market cap that's greater than $10 billion. Of those, only three have investment-grade ratings with both Moody's and S&P. Of those, only two have provided dividend growth that's been greater than 10% over the last two years, and of course, Williams is one of those. We truly believe that this can't continue to go unnoticed, and that the value proposition of Williams is just too strong.
We are exhibiting a significant amount of financial discipline, and we have quality assets and diversity that should allow us to provide attractive stability and growth to our investors over the long term. I want to end with this, a few key points. Again, Williams is large and we're growing. We remain focused on natural gas and NGLs, and we expect to see demand grow over the long term. We have some of the absolute best assets in the space. We are large and we're fee-based. We have a history of EBITDA stability and predictability, as evidenced by the numbers you saw here today. We are exhibiting capital discipline with a focus on improving our return on capital employed. We're taking advantage of selectively selling assets to private capital at attractive multiples. Our leverage is improving.
In 2020, we're moving to free cash flow positive after dividends and capital investment. Finally, we have an attractive yield, projected growth, and we're significantly undervalued relative to our peers. As a result, we of course believe Williams provides a very attractive value proposition to our investors. With that, I'll turn the stage back over to Brett for, I think, some instructions on Q&A.
All right, we're about to start the Q&A session. If Lane and Debbie could make their way up with the rest of our speakers. We're going to be working on getting the stage set here. If you can just give us a minute or two, we'll be ready for Q&A, and we'll get going. Just a quick reminder, if you do have a question in the room, please raise your hand. We're going to have microphones moving around the room. If you'd wait for the microphone to make it to you, and you can let us know your name and the firm you're with, and then the question, so everyone both here in the room and participating via the webcast can hear the question. We'll be able to answer those up here. All right. Do I have my microphones? I've got my microphones. All right.
Any questions, let us know. Abby, we got one back there with Jeremy. Grace.
Good morning.
Morning, Jeremy.
Jeremy Tonet, JP Morgan. Wanted to start off with a couple of questions on capital allocation, if I could. You reduced the CapEx, I guess, that was expected for 2020 down a bit versus what, I guess, prior expectations were. I think you touched on that a bit. I was wondering if you could expand a bit more on what were some of those deferrals. Was it really just NESE getting pushed back? Were there other items in play? It looks like the Transco CapEx kind of stepped down to like $720 million for 2020. Wondering, is this a breather? Do you expect it to kind of bounce back to get you to that $2 billion-$3 billion range? Is that a 2021 event? How do you think that kind of unfolds?
Yeah, great question, Jeremy. I'll take that and let Mike and John fill in if need to. First of all, I think you should realize that our decision to not allocate capital to NESE came up here fairly recently. That permitting process was getting drug out. Things changed in terms of the timing of that from our perspective. Frankly, we just didn't feel it was prudent to continue to allocate capital available for that project. That came down pretty quickly. I would tell you, we certainly have other investment opportunities, frankly, we kind of like the outcome that we're getting out of that by being able to really show what the free cash flow can do. I can tell you, both the board and the management team are very focused on improving the credit metrics, and so that provided us an opportunity.
As we look forward, there's certainly a lot of opportunities out there that we're pursuing and hanging around the hoop, but they're going to have to compete with what we think the value is of further debt reduction out there in time. Frankly, while we're disappointed with the timing that's occurred on NESE, actually, I think it kind of helps highlight
Where how fast we can get after some of the other goals that we have in our portfolio. I will say this, though, and I think I've been forecasting this for quite a while. We are going to start to see growth on lower capital budgets because as we continue to forecast the growth, we have growth capital in the Northeast. It's becoming very high return incremental capital available for us out there because as Michael pointed out, our big systems are built out. You're going to start to see a lot more outsized returns on more limited capital. Likewise, in the deepwater Gulf of Mexico, there's a lot of that tieback, like in the Eastern Gulf there, that is coming to us, but requires no capital on our part whatsoever. It's an infinite return, but it doesn't show up as CapEx.
People look at that and think, "Well, how can you have growth if you don't have CapEx?" The truth is, we've got a lot of places where we're going to have growth with very little CapEx. We will see that in both 2020 and 2021, and into 2022, as we start to see the deepwater really have impact. The earliest we will see that, of any meaningful amount, will be in the first part of 2021 in the Eastern Gulf there, with some of the Kosmos activities going on.
Great. Just following up on that, I guess. You have a great track record, I guess, in recent years as far as M&A and transactions that really were nicely de-levered you. Absent any of those materializing in the near term, just wondering what you think the trajectory is to hit that 4.2 times that you're targeting. How long would it take to get there? Then once you get there, how does that change, I guess, your capital allocation philosophy? If you're kicking off free cash flow next year, it seems like things are changing a bit there. How do you think about buybacks versus CapEx at that point, once you get the leverage where you want it?
Yeah. I'll let John take the first part of that question. I'll answer the second part. John, if you'll answer the trajectory question here a minute. On the question of buybacks or dividends, I would just say, we know everybody wants us to say exactly what we're going to do. The truth is, it's kind of silly to be saying exactly what we would do when we don't know what the share price is and what the alternatives are for that capital at that point in time. Certainly right now, we see Williams as an extremely attractive investment in our shares. Priority over that is getting our credit metrics in line first. Certainly, maintaining and growing our dividend is very high priority.
Behind that would be investment opportunities up against our share buybacks, and that'll be highly dependent on price of the stock, obviously. John, you might take that trajectory.
Yeah. No, Jeremy, before, I think we've told a lot of investors that we felt like we could trend towards that 4.2 number towards the end of 2021. Certainly, some of the pullback in the Northeast creates some question around that. We believe that's going to return. Does that return in 2021 or 2022 with a lot of that producer activity? I think that could have some influence. We expect EBITDA to continue to grow. Again, we're not putting on additional leverage to do that. That's certainly something that's benefiting, bringing that leverage down. I'm not going to tell you with certainty that I think we can get there naturally in 2021 with just EBITDA growth, because again, I think it's somewhat of a function of the price response in the commodity market.
What I can tell you, though, is Chad and his team are very focused on transaction opportunities. If those do present themselves, it certainly would allow us to get there fairly quickly.
Hi, good morning, guys. It's Shneur Gershuni with UBS. Just sort of to continue on the discussion with respect to the Northeast. When I was looking at slide 51, it looks like you expected to have fully contracted revenue to be at about $2.5 billion by 2022 versus what looks like about $1.8 billion today. How much of that delta is NESE versus other projects? If you can give us a little bit more color on how you expect to get there, would be greatly appreciated.
I'll take that.
Yeah, I'll take that. NESE is included in there, in the outer years. That goes out to 2022. The volume as well as the revenue growth would be in there. Also the two projects that I spoke of, the Regional Energy Access and the Leidy project are both in there as well. Those are obviously the ones that are large and that will come online in that timeframe between now and 2022 with those three projects.
Southeastern Trail.
Sorry, Southeastern Trail, which will come on next year, which we're currently just about to embark upon construction there. Those are the four major projects that, including the ones we brought on this year, that would contribute to that.
Perfect. Maybe as a follow-up, I was wondering if we can talk about counterparty risk for a little bit here in the GMP segment. Just wondering how you're dealing with the question today, how you're dealing with any requests that come in. If I recall correctly, a lot of the contracts with Chesapeake were restructured in 2016. Are there many that are left to be restructured? Are there many that are above market? How do we best handicap the downside risk? Although obviously, I would expect that you would prefer not to have that occur, but how do we handicap that?
Yeah. Great. Well, certainly a lot of attention has been around Chesapeake, obviously, in the stock. It is so clear from our perspective what the risk and the opportunity is about that. The first thing I'll say is the biggest thing that is an opportunity for us with Chesapeake, is for them to have more capital available against the great acreage that they have dedicated to us. I would tell you, the situation they've been in, where they're undercapitalized relative to their opportunity, is probably the biggest detriment that we have in our relationship with Chesapeake. They've done a great job. They're a great operator. Had a great relationship with them. That really is the issue.
Relative to the question of bankruptcy, this one really frustrates me because it seems like the perspective is so out of tune with reality on what a gathering contract is and what happens in bankruptcy. I've been in this industry now and very closely associated with the gathering industry for over 33 years now, and I have not seen one of our contracts, under a gathering contract, through bankruptcy for us not to get paid. I have seen plenty of long-haul pipelines where we've gotten stiff, particularly on liquids pipelines. I've seen us get stiffed there. I've seen on processing contracts where we don't own the hardware back to the wellhead. On a gathering contract, there is no other feasible way to move the commodity to the market and get paid than to own the gathering system.
If you think about the opportunity to reject a contract, you would have to believe that the avoided cost of building a brand-new system out over the top of another system where the reserves have already depleted that you originally built it for, that you could do that at an avoided cost that was better than that current pricing. Frankly, that opportunity just does not exist out there in the market. If you think today about our position with Chesapeake, the three areas that are significant with us is the Eagle Ford, where I'll remind you, there's also a big Chinese producing company that owns half the reserves behind there. They're not going to sit and let the bill not go paid and the product not move. You really have to think about through the way a joint operating agreement works on production.
Two is in the Haynesville. Today our rate in the Haynesville is attractive, but we think there's going to be new capital brought in to work against that acreage. We're excited to work on that and help that occur. Finally is in the Bradford County area. Remember that Chesapeake's only about 40%, even though they're the operator on a lot of that production. They're only the bill payer on about 40% of that production. The rest of it, Equinor, Total, Chief, very well-heeled operators out there. They are not going to let the production get shut in. They would just move the portion. What actually happens in that case is the reserves in the ground get reallocated to the party that is not producing.
The full amount of the gas stream still continues to move, and you just see an allocation in the reserves in the hole. I would tell you, even then, we haven't seen that occur because the banks, whoever the creditor would be in that situation, are not going to not see the bills paid. The Bradford County area is the one that really is surprising to me. That is the lowest gathering rate of any of our gathering rates in the Northeast is on the Bradford County system, because that cost to service model has worked very well because the volumes have been higher than the original expectations.
I would just tell you, it's really, I think, frustrating for the management team because it is so clear-eyed in our mind about how that really works, that we really don't see the big risk on that. The real risk and the thing that we always want to work with Chesapeake on is bringing new capital up against this dedicated acreage. I would just tell you as well, that team has done a great job, and I'm not going to forecast where they go on that issue, but they've done a great job of continuing to keep the equity in the mix and continuing to do a lot of interesting transactions to keep themselves well-positioned.
I would just tell you from our perspective, we're not going to try to call the shot on that one way or the other, but we think that's a very capable operating team. If you were a creditor or a bank, I don't think you'd be wanting to see that group displaced because they've done a great job up against the conditions that they've been dealt. Anyway, I would just say from our perspective, long-haul risk with producers and not narrowing that to anyone, but long-haul risk with producers is risky because once a pipeline is built and the bases collapse, you don't necessarily need that to continue to pay that long-haul obligation. That's really where a lot of the risk exists. On the gathering side of the risk, it just hasn't proven itself up in the market, and we really haven't seen that.
Sorry for that very long explanation. John or Lane, anybody else want to weigh in on that?
No. Look, I think Alan said it correctly. In order for any of our gatherers, if they're going to file for bankruptcy, to get out of those contracts, there's a lot of hurdles to get over, and we've taken a close look at that, and it just wouldn't make sense for Chesapeake or really any other of our customers to reject those agreements. They can't pick and choose what they like and what they don't like in those gathering agreements. They either have to reject the whole thing, or they have to accept the whole thing. There's no business reason they would do anything other than accept them.
I would just add some metrics to that too. Specific to Chesapeake, we've obviously reduced our exposure pretty significantly there. We did the Powder River Basin transaction, of course, in the Northeast, we've had CPPIB that acquired the Encino, acquired Chesapeake assets there. Towards the end of this year, I haven't seen the final projection, but I would suspect Chesapeake will be around maybe 8% of our revenue. If you think about the diversity of their gathering systems, the three gathering systems Alan was referring to, there's rumors about the Haynesville, whether or not something happens there. If that were out of the mix, it would drop to 5% or maybe even inside of that.
Specific to Chesapeake, it's just not that material beyond the fact that the gathering systems we view to be very low risk as far as anybody's ability to ever reject those contracts.
I really appreciate all the color. If I can just follow up on one small part of the question. Outside of the joint operating interest type wells and systems, are there opportunities for you to maybe tweak your agreements with Chesapeake, to sort of help them out and potentially create an NPV neutral scenario for you where you get more volume somewhere else or something of the sort? I believe that's something that you did pursue, a couple of years ago. I'm just wondering if that was an opportunity.
Yeah, I would say we've pretty well worked through that. The Eagle Ford renegotiation that we did recently really was a trade-off between getting volume certainty from them and us not raising the rate as high as we could have under the cost of service agreement. That was the trade-off there because we had no certainty of volumes under that deal. Now, we do have certainty of volumes, but in exchange for that, we agreed to not raise the rate all the way up to the cost of service model, because frankly, that would be somewhat of a death spiral, and at the end of the day, we'd be left holding the reserves, and that's not our business. We certainly think they're a great operator, and we want to help see them succeed. I think that was a great take.
That's really about it. If you think about the Haynesville, I would say if there was a party that came in with a lot of fresh capital into that area and could really show us with credit and a big obligation to a pathway to growth, there would be some opportunities around that, but don't really see much in the Bradford. The Bradford model's working very well. That's really the extent of the opportunities I think that are out there.
Thank you very much, guys. Really appreciate the color.
One last here.
Durgesh Chopra with Evercore ISI. Thank you for taking my question. Just a quick housekeeping one for me. Sorry if I missed it. What level of maintenance CapEx, John, should we be modeling for 2020?
That's in your book in the appendix, but we have around $500 million in maintenance capital in 2020.
Thanks. Just a couple of weeks ago, FERC lowered the ROE on the electric transmission assets. I'm sure you guys saw that. There's an open ROE review proceeding on gas and liquid pipelines. Any update on that process or any color that you can give us from your recent rate case settlement, or at Transco?
Mike, you want to take this?
Yeah, I would say that the projects that we're doing along our growth capital projects on Transco, those are negotiated rate contracts. There ultimately will be an embedded ROE in a cost of service rate that we also have to calculate, but we negotiate those contracts, therefore we can enjoy a slightly higher return than maybe what FERC would be allowing to a cost of service rate. Through that trade-off, though, we're taking construction risk on the cost of that project, which we feel very comfortable doing, and we are enjoying a very nice multiple on those projects. I would tell you that's where we're at on our FERC-regulated pipeline systems today, where we're going to go out and negotiate rate contracts on those deals. Ultimately, where FERC goes on new projects, I don't think will be as impactful on us.
The ROEs that we're currently being able to negotiate in settlement agreements that are deeply embedded in those, you can back-calculate those, but we're very satisfied with where those are today as well. I don't think there's going to be significant pressure on that going forward because it is an environment right now that is more risky than it has been in the past in regard to the FERC-regulated pipelines and the projects associated with that. I just don't think there's going to be as much downward pressure as you might think there.
Yeah. One of the things that was powerful in this rate case settlement discussion, whether we like it or not, this is some really bittersweet news for this crowd. Because the cost of capital for the midstream and the pipeline players is so much higher right now than the utilities. In other words, you saw my picture on yield, our yield versus utilities. That goes right into a cost of capital calculation about what we should be allowed for return on our projects, and that is how that's determined. The low equity prices that we have in the space right now actually gives us a very strong argument for higher ROE in those rate case, and that certainly came through in this last rate case settlement.
Praneeth Satish, Wells Fargo. Just wondering on Transco, how much more modernization CapEx could be spent over the next few years? I guess tied to that, has there been any thought of filing rate cases on a faster basis to recoup that cost more expeditiously?
Well, if you recall in our rate case filing that we had, we had an emissions reduction program embedded in that filing, and we do have a path forward to achieve success there, we believe, with our customers. We had about $1 billion of investment opportunity, we felt like, over a long horizon, five or six years, where we could go out and continually find ways to reduce emissions on our compression fleet, improve our reliability on our compression fleet. Take costs out of the business as well. There's a number of different ways you can do that. You can do that via pancake rate cases, one after the other, or you can do it with an emissions reduction program tracker. We certainly think we like the tracker program better. Ultimately, I think our customers will like that mechanism better as well.
I won't get into all the details of the settlement, but as you know, typically, there is a comeback provision in those settlements embedded in that and a stay out provision. Our settlement is no different. When we divulge that information, you'll see that. Yes, the answer is you could go back and you just continually do rate cases and you have to look at the environment you're in when you do that to see if that makes sense. We think from a certainty standpoint for our customers and ourselves, we can go in and utilize the tracker mechanism to really give certainty to customers. We can predict what that rate change will be over time through a tracking mechanism, and we can stay out of rate cases.
Okay. Just quickly on the operating margin, do you have a target of where you think that could get to and how many more years of improvement could we see there?
Yeah, I would say on that, there's absolutely a certain amount of money you need to spend to operate your business and operate it properly, I would say. I won't predict where we're going to go. I would say, generally, we can continue to improve that. We're finding ways to take costs out of our business. If you look at our revenue, we can also grow that operating margin ratio by increasing our revenue faster than when we're increasing our costs. That's one of the other mechanisms that we look at to take advantage of there. I think if you're in the low 70s, you're doing really, really well. That's top performance today. We're at 67% today, and there's absolutely a certain amount of money you need to spend on your integrity and properly maintaining your assets.
We're going to continue to do that properly.
Hey, guys. Michael Lapides of Goldman Sachs. You all have been very good about being transactional about assets that you thought weren't as attractive as items in the remaining asset base. Can you talk about going forward a little bit about how when you look at the portfolio, and it's a very diverse portfolio, what you think within it could be considered non-core, or how investors should think about what's left, what might fit into something that's less attractive to you going forward versus other uses of that capital? After that, I have a follow-up one.
Chad, you want to take it?
I'd start by saying, I think we look at a combination of things. We talked a lot about value dislocation, I think that that's an important area where we spend time and focus. I'd say that, we have gradually moved towards the lower-cost capital. If you think about transactions that have been done in our space and that we've pursued, we've moved from private equity looking for high returns to infrastructure looking for more modest returns to now, investors that are looking to invest in long-term, high yield, stable cash flows. Oftentimes, those investments, they would like to make those investments alongside an existing stable operator like Williams. As we look for lower-cost capital, one of the areas where we're focused is like our transaction in the Northeast, looking at capital providers.
One of the things we find interesting, we were talking about in the break is, you look at the Four Corners transaction, that asset would have likely been at the very low end of what someone's valuation might have been in a sum-of-the-parts analysis of our assets, yet it had very predictable cash flows and very high-yielding cash flows. A long-term investor can look at those predictable cash flows and put a very low discount rate on that investment. Those are the kinds of assets that we have a lot of, and that for whatever reason, the public market doesn't see the same kind of long-term value, at least in today's market. I would say that we will continually look for assets that are not core and don't provide us with a strategic advantage, integration, value chain integration, scale, opportunity.
The most, I think in today's market, one of the more interesting opportunities for capturing value dislocation is to find those investors that are willing to put very low discount rates on very predictable cash flows, even into cash flows that aren't necessarily high growth cash flows. When you think about our portfolio and where we'll put our energy, I'd say that's where we'll primarily be focused.
Yeah. I would just add to that, Michael, to be clear, a lot of the space out there today, that private money is looking for a great operator as well. We can maintain our scale, and we can maintain a lot of synergies, just like we did in the CPPIB transaction. We can actually grow our scale like we did in that case, by bringing that low-cost money in, but liquidating some of the investment in the asset through a joint venture. We can maintain our scale, and get higher value on a portion of those assets. That's why if I were going to give you some foresight into what to think in the future, I would have my eye on those kind of opportunities more than outright asset sales that are going to be meaningful for us.
Got it. Thank you. One follow-up just on 2020 CapEx guidance. Roughly $500 million in maintenance, if I heard that correctly, and please correct me if I'm wrong, $1.2 billion in growth, and of that growth, about $400 million in the Northeast G&P and $200 million for your portion of Bluestem. That implies ballpark around $500 million across Transco, the Northwest Pipeline, the Gulf. Do you view growth CapEx at Transco, Northwest Pipeline, and in the Gulf as at a lull year, that this is a trough year? Do you look at this and say the next few years may look like this?
I would just say, on the graph that I had up there with $400 million of CapEx in the Northeast, that was maintenance and growth combined, to be clear on that. That's rounded up. A portion of that is growth, a portion of that is maintenance. I would just say, it's highly dependent upon what projects that we have that are out there on our horizon. The NESE project's a billion-dollar project, the bulk of that will be spent during construction. Once we go to construction with that project, you'll see a significant uptick in regard to that capital investment opportunity there. Regional Energy Access is going to be $800 to $1 billion. The majority of that, once again, will be during construction. That's a 2023 in-service date.
It may be a little lumpy depending on where the opportunities are coming to fruition for us. It's hard to predict exactly what and how to pinpoint that, and that's why you see a sideboard there, but $2 billion to $3 billion that you saw on Chad's slide. I do believe the bulk of that will be spending on our transmission assets here in the foreseeable future, just because of the breadth of opportunities that we have on the Transco system alone. Our Gulf of Mexico opportunities as well, we consider that transmission out there in the Gulf. There will be some capital investment opportunities there depending on when the producers FID those projects as well.
Gabe back there.
Here.
Somebody get Gabe right back there.
Hey, Alan, I think we've got the mic. It's Becca Followill, U.S. Capital Advisors.
Oh, sorry. Sorry about that. Somebody get Gabe. Gabe's been having his hand up, so Gabe gets the next one. Go ahead, Becca. Sorry. No, now. Go ahead, Becca, now. I'm just saying.
Okay. On the 5% to 7% long-term growth rate, near-term, there's some headwinds. You've got producers in this strip going to basically flat production in the Northeast. NESE's gotten on pause, I would put it that way. Gulf of Mexico's really 2023, 2024. Over the medium term, do you guys see yourselves hitting the 5% to 7% target EBITDA growth rate? How do you define long-term when you say 5% to 7%?
Thank you. I would just say, first of all, on the growth rate that we have here in the near term, if you look at the growth from 2019 to 2020, you really have to back out. Commodity prices in our deck are flat from year to year, we're expecting continued low prices. That's a little bit of that NGL margin. When you're talking such low percentages, that's a driver. The $100 million of deferred revenue loss that we've got mostly in the Barnett there, that's just a step down in that deferred revenue. Really the growth on the $2.2 billion from 2019 to 2020 is about 4% on real new cash flow coming into the system. That's about what we would expect, frankly. We've talked about $2.5 billion-$3 billion.
As I said earlier, the thing that drags that down, in other words, that return on invested capital down, what drags that down is actually our transmission projects in the short term, because it's very long-dated capital, and it's not as high an incremental return as we see in both the Northeast and in the deepwater Gulf of Mexico, because we just got latent capacity, and so we get very high return. As we think about what's going to drive 2021, I would point out that certainly we've got tiebacks that we are in very late stages and don't see much way for that to go away. Some big tiebacks to come on in early 2021 in the Eastern Gulf that will drive quite a bit of new cash flow. Bluestem is a very high return investment.
That will be done here at the end of 2020 and start into 2021. Cash that has been going to pay others will start to come to us. A lot of incremental return on those projects, on things that we have been, in that case, paying others for. Pretty high return projects in the 2020 timeframe, but we do not have a lot of transmission capacity investment in there on an absolute basis from in 2020 that will drive 2021. As you get into 2021 and 2022, a lot of the projects that Michael talked about, like Southeastern Trail, Leidy South, Regional Energy Access start to come on, and those are certainly pretty meaningful. I would just say we have a lot of high return, pretty potent return in the 2020 timeframe into 2021 and to 2022.
The growth rate there is going to be somewhat dependent on what we see in these gas basins. I know the world thinks that gas demand is going to completely stop, and we're not going to see growth out of those basins, and we just frankly don't believe that. We think the growth is going to have to come from somewhere in terms of gas demand growth. In 2021, while we're not forecasting that right now, we do think there's pretty good upside to our growth. That will come from places like the Northeast gathering volumes, the Haynesville gathering volumes, and places like the DJ Well that's continuing to grow pretty well.
I would say there's a lot of different ways we can win, a lot of different environments that we win in, and if low gas prices continue to push down, it is just going to put that much more pressure on the Marcellus, the Utica, and the Haynesville to deliver against that demand growth, that we think is really hard to deny the demand growth that's out there. It can't really sneak up on you. It's pretty evident at this point from our perspective. That's how we see things. I think the 5% to 7% does not always require $2.5 billion to $3 billion now for us because we've got so much latent capacity available in areas that we're seeing drilling activity. That's a good thing for us. It is pretty hard to predict.
I would tell you, pretty hard to predict exactly the timing of that beyond the transmission projects. Transmission projects other than NESE are pretty easy to predict at this point. The rest of it in terms of growth rates, whether it's going to come from the Haynesville, the Northeast, or the deep water, is a little more difficult to predict.
Thanks, Alan. I feel like I should lob you a softball after you insisted with the question. I wanted to ask you a broader question on the current backdrop for natural gas. You talked about collaborating with, I think, EDF a couple years ago on methane control. It seems like the debate has gotten more polarizing than ever, particularly here in the Northeast. Is there anything you're contemplating doing to try to shift that dialogue, supporting a CO2 tax, methane control, stringent controls, running more commercials on TV, like one of your competitors? Is it just kind of a hopeless cause in your view, and we just need another polar vortex to come through before people realize that, hey, we may need more capacity?
Yeah. Thank you, Gabe. I think we are way behind on communicating as an industry. If you think about just for those of you all, a lot of you all I know in here, and you've been around long enough that I'm telling you something you already know. Back when we had the America's Natural Gas Alliance, or ANGA, which was made up by the independent gas producers, they had a budget of about $85 million-$90 million a year in advocacy around natural gas, and that was fairly effective. Gas prices fell away, so did all that money and that support around ANGA. There really hasn't been a messaging out there today for the pipeline industry.
I would say we've let ourselves become associated directly with oil and gas and fracking of oil and gas, rather than being associated with the little blue flame that everybody loves on their stovetop. Frankly, we've got to change that dynamic to where people really do understand that you can't have the luxuries that you enjoy, low cost, clean energy in your home, if we're not building pipelines. I would tell you, there's a pretty large movement going across the space on that, to really promote the benefits of natural gas and get the consumer to understand what all benefits we've been realizing from that. We're way behind on that message. The good news, I would tell you, is the utilities understand the dilemma as well, and they are really starting to become supportive of that.
That's really important in my mind because they have much better access to the public than we do as a pipeline company, or frankly, the API does through the oil and gas companies. We think that message, from Williams' standpoint, we think that message needs to be carried through the retail arm, and we are very much in the middle of trying to make that happen. On the more complicated question of carbon pricing and kind of repositioning the industry, last week you saw the NGSA just recently come out with saying that they supported some kind of carbon controls or pricing. I think that's a big shift in the industry. I can tell you, I've been working on the National Petroleum Council infrastructure study that's been going on almost two years. It seems like it's been about 10 years.
It has been a very long, exhaustive study trying to get the energy industry collectively to have a voice around what we want to say around carbon and carbon reduction. While it's been very difficult to get those voices to come together, I think we've done that. The good news is we've had a lot of NGOs in the room with us coalescing around that message. That is very promising to me because if we're really going to take on carbon reduction, just waving our arms and saying it's going to happen and we're just going to stop fossil fuel use immediately without a plan for how to do that, is not getting us very far, and it's not going to get us very far.
Having the energy companies engaged in that process and really looking for real, live scientific solutions on how to do that is where we need to get to. I think over the next six months, you're going to see the industry leadership really move in that direction with a much more conciliatory and cooperative tone to the middle. I'm just hoping that we can draw that out of the NGOs as well, because it is high time that we really get together and work on real, live, practical, and feasible solutions. There's many of them out there, but we're not going to get there if we just take very polar positions on it the way things have been going. Thank you very much for the question, Gabe.
Maybe just to add also to that. We strongly believe is not a hopeless cause, and that's not just a hope of ours. We've been out doing quite a bit of work polling, and we've been taking a data-driven approach to not only our projects, but to understanding the climate around our industry. I think it's one of the reasons why, obviously, New York is not easy from a project development perspective, but the fact that we are still a constructive part of the conversation. Our project actually polls very well with demographics that you might think it might not. Our projects are designed to bring lower-cost solutions, lowering emissions immediately. What we've found when we've polled is that in the absence of us telling our story, people have a negative view of natural gas. They don't understand and connect it to the benefits of their daily lives.
When we get out and actually connect with people and tell our story, there is an 80% support for natural gas and Williams's business in particular. The problem is, in the absence of that story being told, it's typically on the other end of the spectrum. The good news of that is that our mission is something that people will support. The challenge that we have is that we haven't been out there carrying that message as effectively as a very small population of dissenters are. I think the question about, is there hope there? We are very encouraged by the opportunity. We've got an industry that hasn't historically had to go out and flex the muscles of telling our story and competing for people's attention, in that kind of way.
I can tell you that as a company, we've been really leading on understanding the market around our projects and around natural gas in particular. We think we've got a really positive story to tell, and we think we've backed that up with actual outreach that confirms that. We just need to now get out there and tell our story better.
Thanks, Alan. Thanks, Chad. If I could just get two quick follow-ups from Mike and for John. One for REA, Mike. Is that contingent on PennEast going through it all? It seems like that project parallels PennEast a bit.
For John, can you give us your latest and best estimate for when Williams might be a significant corporate cash taxpayer?
I would say our route obviously parallels the PennEast route for Regional Energy Access, we have a subscription level today that would justify our project regardless of what happens with PennEast. We intend to go forward with the project based on what we have today. If PennEast doesn't go forward, I think there'll be even more demand for Regional Energy Access capacity, and we'll have to evaluate if we can upsize that project.
On the cash tax side, we still haven't changed the projections. We don't intend on being a cash taxpayer, at least through 2024 and into 2025. There's a lot of discussion about the new tax code changes that could come on the back end of the previous changes President Trump pushed through. If we continue to see some kind of treatment for growth capital investment, obviously, that could extend that even quite a bit further. Today, our guidance is exactly where it has been all along, at least through 2024. We're not a cash taxpayer.
Hi, Jean Ann Salisbury from Bernstein. There have been a lot of questions this year about the true free cash flow generation potential of G&P assets. I thought slide 48 on Northeast G&P was really helpful. You're obviously still growing a bit in 2020 with the $400 million spend. My question is slightly less than the $400 a good, safe, flat estimate? Or is a lot of that $400 still front-loaded, and it's actually substantially less than that to stay flat?
Jean Ann, I would say a lot of that growth capital that we have there, like I said earlier, that's $400 million of growth and maintenance CapEx. The bulk of the growth CapEx that we're spending there is in the Bradford under our cost of service agreements. That will be spent throughout the year, next year. This is primarily compression-related projects as well as well connects that are covered in our cost of service agreement with a nice rate of return on those. That's the bulk of our growth there. We have some additional growth in many of our area growth CapEx in many of our other areas in the Northeast as well. We do expect to continue to see some growth CapEx expenditures there, and it does result in growing volumes in the Northeast.
Not nearly at the trajectory that we've had in the past, obviously, but we still anticipate some growth there.
Just another follow-up on Regional Energy Access. If you're using the same, or roughly similar route to PennEast, can you talk a little bit about why you have confidence that Williams will have a better outcome than PennEast has had so far?
Well, the one benefit, the great benefit that we have that I alluded to in my discussion was the corridor that we've established. We're building alongside our existing pipeline. It's not a greenfield pipeline like PennEast is. The bulk of our construction, in fact, nearly all of it, with the exception of one compressor station, is in Pennsylvania. It's not in New Jersey. We would have a greenfield electric-driven compression facility in New Jersey, but other than that, all the assets would be in Pennsylvania that we would be building. This is the beauty of the Transco corridor. We take advantage of that everywhere we can with small looping projects, small compression projects, that result in very large expansion opportunities for our customers there. That's why we have a lot of confidence.
We have binding proceeding agreements in place with the customers at the subscription level that I talked about there, and that's why we have a lot of confidence in the project.
Michael, your slide showed a dotted line along the entire contract route, but that's not all construction.
Right. That's the contract path, those dotted lines that you saw. Thanks for pointing that out. Very small amount of looping required to effectuate that project.
Thanks. That's helpful.
Thanks, guys. Derek Walker, BofA. On slide 74, there's a long-term EBITDA number. It looks like the high end of the range is about $9 billion in 2028. Just wanted to see what some of the longer-term assumptions. Alan, you talked a lot about 2020, 2021, and even 2022, but as you get further out, does that assume 100% project capture from the backlog that you guys mentioned? I think there was about 19 projects in that backlog, and does it also assume more operating leverage as far as the less CapEx, but growing EBITDA from, you mentioned the opportunity in the offshore as well. Just wanted to see what that sort of 2024, 2028 assumptions are there to get to that $9 billion.
In other words, what the capture rate or success rate should be against that backlog? Is that primarily the question? First of all, I would say there are projects in there now that are in our execution mode that were not in that backlog 19 months ago. There's some that will come in and some that will go out, obviously. One of the things we had in backlog there, we had project one and project two, if you'll recall, in the Analyst Day. Project two is obviously Leidy South, and that project's going ahead. Project one has taken a different form. It is in that backlog, and I would say it's looking as good or better than it has based on demand. It's kind of reforming itself. It is somewhat contingent on some other projects coming forward.
I would say that backlog is feeling pretty good just based on the request for proposals that we're getting from customers along the corridor pretty rapidly. Michael, you saw the presentation he had around the amount of coal plants that are still in the markets, and obviously, that requires a lot of gas to replace that. There's quite a bit of demand that is growing, and new projects and new requests are coming in all the time. Some of that will not happen, and some of it will, and some will show up that's not in there today. Michael, I don't know if you'd add anything to that.
No, I think you covered it well.
Yeah, I think you're referring also to the 10-year. I would tell you that we obviously don't provide guidance on that far out. The process that we go through, you heard a lot of focus on the fundamentals. We ensure that there's a fundamental backdrop that supports long-term growth. We identify individual projects that we have line of sight to for as far as the eye can see. We risk those projects. As you can imagine, as they get further out in time, we put more risk on the opportunities. We have a much larger inventory of opportunities. It is not assuming 100% capture of the project opportunities that we believe we're going to see over time.
In fact, as you get further out in time, many of those projects are 10%-20% kind of risked projects. We have such an inventory of projects. We have a relatively small amount of unidentified wedge that we see through the platform. When we talk about confidence in our ability to grow, we see that the platform has a tremendous inventory, and that's not just hope. That is going out to every franchise, every franchise owner, and identifying individual opportunities and then putting a risk against those opportunities. We even then oftentimes risk that further to ensure that we've got confidence in our ability to keep pulling those levers. That's what that slide was. Again, it's I think a broad range. That's how we go through that process every year.
Thank you.
Right here.
Chris Sighinolfi with Jefferies. I just have two questions if I could. John, appreciate your slide 99, looking at the refinancing opportunity on some of the near-term maturing debt. Just curious, some of your large cap peers take different approaches on this. One is terming out stuff 30 years or however long they can. Others are still reliant on sort of short-term fixed or floating swaps. I'm just curious, is 10 what you budget, or is that what we should assume, or would you push maturities further than that if you could?
We would certainly push maturities to 30-year rates where we see the rates today. It's going to have to be a function of where we are at the time. Again, I would reiterate the point that as we think about maturities in 2020, we are being sensitive to some of the activities we're looking at on possibilities that we could sell interest in assets. We don't want to get in front of that. We are creating a small amount of excess cash flow, even above dividends and capital spend as well. We don't want to get in front of that either. Certainly long-term rates, 30-year rates are still very attractive today. To the extent we did have a new issuance, I think we'd look very long and hard at a 30-year rate.
Okay. Thanks for that. Appreciate the conversation in response to Gabe's question on just the industry at large and repositioning the mindset of the public towards what it is you all do. I'm curious, Alan, versus last Analyst Day, now this one, when we think about the forecast for next year, we're going to straddle a national election. I know a lot of your issues have been more of a New York statement, municipality issue in terms of frustration on what you guys are going to do. At the board level, how do you guys think about changes that might come, changes in FERC majority that might transcend after an election, as it pertains to what you plan on doing next year, as you start the groundwork on what might come in 2021?
Yeah. No, it's a very complex issue. We spend quite a bit of time in our board meetings debating what issues we should be prepared for and what scenarios we should be shifting to. Even if the current administration continues to exist, there's a lot of shifting going on within the industry and industry's attitude towards things that's going to change things as well. I would say that I think there's change coming, whether it's through administration change or just the energy industry's approach to the issue. We do look at scenarios around where we would be exposed, what kind of changes would occur. I think we feel pretty well-positioned. Probably the area that would change trajectory longer term for us would probably be the deepwater.
If there was somebody came in and said, "We're not going to lease anymore," it's not going to be in the short term likely, because those leases are already established and the operations and the efforts are already going on there, that probably wouldn't be shut down. Even then, it is really hard to imagine some of the extreme cases that are being pointed out. There's a long-time oil and gas leader in Tulsa named Charles Stephenson with Vantage, and he said, "You know, I think we're in pretty good shape here, one way or the other." Of course, this is a guy that's got a lot of holdings along a lot of existing reserves in the ground. If you think about the outcome of that, it would be really good for that oil and gas investor.
It would be really bad for the whole industry, and certainly for our industry. The fact is, a wholesale attempt to that just is not very practical about continuing to grow our economy on that. I've got faith that cooler heads would prevail in terms of what the administration. To answer your question, we do look at the risk and we think about, well, where would we be exposed? What areas might shift? The Northeast, there's hardly any federal lands at all in the production in and around the Northeast, so that's not a very exposed area. New Mexico has a lot of federal lands that's drilled on, so in the Delaware Basin. The Rockies, places like the Piceance, there's a lot of federal lands there as well. There are places where there's a lot of BLM property.
San Juan Basin's an area where there's a lot of BLM property. Those are areas that you would want to keep your eye on, but it's pretty hard for me to imagine that there's any wholesale reduction, because this is not a very feasible outcome over the long term.
Just coming back to your interest question, too. In our slide deck, I had a 3.5% rate. I will tell you in our guidance for 2020, we have a higher reborrowing rate than that. About 0.5% higher, actually, in our reborrowing in our guidance. Beyond that, too, that 3.5% rate's a presumed Williams rate. Obviously, future financings, while we could go out to a 30-year maturity, we also will do some financings at Transco, which borrow at a cheaper rate than Williams. Blended, I think that slide holds true to the value creation.
All right. Thank you very much.
Thanks. Okay, I think we've got time for about two more questions here. If there are any. Okay. Are we done? All right. Very good. Well, thank you all very much for joining us today. We really appreciate all the attention and the interest in the company, and we look forward to continuing to run the business well and generate value for our shareholders. Thank you very much.