Good morning, everyone, and welcome to our second day of presentations. Today, our speakers will cover our traditional analyst presentations. During production, we've taken measures to ensure appropriate social distancing between our speakers. Before I turn the presentation over to our first speakers, I'd like to take the opportunity to say that during these presentations today, our speakers may make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, based on the beliefs of the company, as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. Now I'll turn the presentation over to our co-CEOs, Jim Teague and Randy Fowler. Welcome to the second day of our virtual Analyst Day. Yesterday, or the first session, our folks talked about the way we do business. I think this time we're going to talk about the business that we do. Is that right, Randy? We'll start with the first slide. I think every analyst that covers us has seen this slide 10 times over. The fact that we keep showing it says something about how proud we are of it. It's a map of our system, 50,000 mi. What is it? 23, 21, 23 natural gas processing plants, 25 fractionators, 19 deep-water docks. It's fully integrated. If you think about our system, we've been very disciplined that anything we built or we bought had to fit what we already have. That's why it's fully integrated. If we do something in Wyoming with a processing plant, then it's going to go through our pipeline, our fractionators, into our storage, and then our downstream system. We pay ourselves along the way. We don't like to pay third parties. The other thing that differentiates this system from anyone else, I think, is our connectivity to the market. We are connected to every ethylene plant in the United States. What is it? 80% or 90% of the refining capacity east of the Rockies. We have our export facilities that we're proud of, that by and large came from the Oiltanking acquisition. The other thing about this system that's kind of neat, I guess since we bought TEPPCO in 2010, Randy? Right. Since 2010 when we bought TEPPCO, which had a small Crude Oil business. We've built a pretty good crude oil franchise with our pipelines out of the Permian, out of Cushing, and out of the Eagle Ford. That's who we are, and we're pretty proud of this. You may see this in some of the other presentations. We like showing the map because we're proud of it. You want to add something to that, Randy? As far as why EPD, again, some of this, we start off with that beautiful map that Jim showed us. As far as why EPD, I think first it starts with a 23-year track record of investing capital, to build that system map, and the integrated system that it is. We've earned good returns on invested capital throughout this period of time. We've got a demonstrated history of returning capital back to investors. Chris Nelly is going to highlight that here in a little bit, it is a big number of what we've returned back to investors. When you come in and you look at our business, we've got margins of safety out there. I want to say, when we think in terms of gross operating margin, 85%-90% of our business is fee-based, it provides consistency. We've exhibited over that 23-year period, we've exhibited durability and consistency of cash flows, whether it was the commodity price cycle that we saw in 2003, whether it was the financial crisis in 2008, whether it was another commodity price cycle in 2015 and 2016, or whether it's the pandemic that we're continuing to go through right now. We've provided consistency over that time period as far as returning capital back to our investors and still being able to come in and invest through the cycles in good opportunities. A little bit of what gives us that flexibility is probably one of the best balance sheets and one of the best debt ratings in the midstream energy sector. We've tried to stay ahead on trends, I'd like to say. The old MLP model was to pay out all your capital, and then whenever you got ready to either do an acquisition or come in and make organic growth opportunities, capital expenditures, you had to go out and raise debt capital but also equity capital. I think we were one of the first midstreams that said, "Okay, we're going to go to equity self-funding." Basically, I think we gave ourselves, we thought it was going to take two to three years to get there, and I think it took about a year and a half instead. Now, in 2021, we should be at a position, not only are we going to equity self-fund our capital, but we may be able to totally fund our CapEx from our cash flows plus pay our distributions, plus have cash flow left over. Again, I think it's what we call discretionary free cash flow positive. We're expecting to hit that in the second half of 2021. At the end of the day, I think it comes back in, and we hit on a little bit of this yesterday. I think we've built a sustainable business model over the long term. It really starts out, it goes back to what we talked about governance yesterday, that sustainability really comes back with the alignment that we have with our general partner coming in and own 32% of the units outstanding. We eat our own cooking. We're invested alongside our equity holders. I wonder if you guys realize we have what's called the Office of the Chairman. It's Randy, myself, Hank Bachmann, and Randa Duncan. We meet every Friday, and we talk about what's next, what should we be doing. We talk about a lot of other things. Sometimes we talk about politics. Here recently, we've talked a lot about politics. It is an election season. One of the things that this speaks to, and the first slide speaks to, is the diversity we have allows us to come through these cycles stronger typically when we come out of them than when we went into them. That's what has helped us have such a strong balance sheet. The other thing I think people need to appreciate is the teamwork within Enterprise is powerful. I think if you watch Randy and I think we're a pretty damn good team. If you look at Randy's folks and our business folks and our operations folks, the power of the teamwork within Enterprise is something I don't think some people fully appreciate. What do you think? I agree with you. Some of that, just as an example, the way we come in and think of managing customer credit. Commercial team and finance team works, and accounting for that matter, works very close together. One of the things, you talk about credit. In a lot of businesses, it's the credit people that set the credit limits, and there's always this fight between the commercial people and you've seen it, I'm sure. In our company, sometimes it's the commercial guy that takes the lead on saying, "Wait a minute. I'm not sure that guy deserves that much credit," or, "Man, we need to raise this." They don't fight it out. They talk it out, and they decide. Anyhow, it's just an example. You like the way I went off script there? Yeah, I do. Not surprised by it, though. When we come back in now look on the next slide, when we think about long-term capital allocation. A lot of that, you hear us talk a lot about financial flexibility. Well, this is pretty much where the rubber meets the road. Again, we're a publicly traded partnership, and what publicly traded partnerships are geared to do are return capital to investors, and that financial flexibility, keeping that extra margin of safety in our balance sheet, our credit ratios, our distribution coverage, that gives us the ability to come in and maintain and grow that distribution over time, even through some of those cycles that we talked about. It also gives us the ability to come in and not only pay distributions but also invest in organic growth opportunities. When we think about the distributions, last year, depending on how you want to look at it, if you just take cash flow from operations, we used a good bit of cash flow from operations last year for working capital purposes. Our cash flow from operations was lower. If you look at reported cash flow from operations, we returned about 67% of our cash flow to our limited partners in the form of distributions, another 3% in buyback. If you come back in and sort of ignore the cash flow that was used for working capital purposes, that equated more to about 60%. Chris is going to show you in a little while how that returning capital to investors, how that stacks up to other segments in the S&P 500, then frankly, to some of our midstream C-Co rp peers, how we stack up there. I think we stack up well as far as coming back in and returning capital. With that, not only are we first and foremost looking to pay that distribution out because that's the most tax-efficient way to return capital to the limited partners, but we also keep enough flexibility that we can come in and fund some of the organic growth opportunities that Jim's team is seeing. If you pay attention to what we are trying to accomplish, we got, what, $3.6 billion projects under construction, and I think 60% of those are Petrochemical? Mm-hmm. 60%+. Yeah. You get a pretty good feeling. We like primary petrochemicals, and we like going further downstream. I think if I had a crystal ball, I'd say you'll see more of that before it's over. We think as we go into primary petrochemicals, two things. We think it helps our upstream system, because it gives us the longer value chain to leverage. It's a high barrier to entry. You're not going to have a lot of guys going out there and building PDH plants like you have building gas processing plants. When we finish this PDH plant, I think we'll be the largest merchant producer of propylene in the world, if I'm not mistaken. That says something. We've also, part of what we're spending is creating an ethylene storage logistics export trading hub, and we've done the same thing with propylene. We like where we're going and, I think, you'll see more of that. Also, you get good investment-grade customers on those deals, and you get steady returns because they're a tolling type of an arrangement. Good demand growth based on GDP, I guess. Oh, yeah. We see ethylene and propylene growing at 1.3 x GDP. I said this yesterday and I'll say it again. I was with that CEO of a major Petrochemical company, and they say that their polypropylene's flying out the door. As we speak, it's about $0.95 a pound. Yeah. We've got our splitters running full out. They better be. Sure. The last piece of the capital allocation is, again, what we've talked about some on buyback opportunities. This has been, I guess, a road to coming in and getting to equity and total self-funding. We began this back in 2017, and frankly, it's been a pretty big shift in the way we think about funding our capital. This year, we're looking to come in and be discretionary cash flow positive second half of the year. What that provides us, it provides us an opportunity. I think our balance sheet is already in a pretty good place. We say that our leverage objective is the 3.5 x area of debt to EBITDA. What we mean by that is really a range from 3.25x-3.75x. Right now, I think we finished the year right in the middle of that range, so we're in pretty good shape on that front. When we come in and have the discretionary capital, additional capital, then that gives us the opportunity to come in and look at some of these growth opportunities a nd we've talked about this, they're really consistent with some of the themes of what we're seeing with energy evolution and energy transition that also integrate in with our existing assets. The other place that it comes in is it does give us some opportunities to come in and do buybacks. I think we've got a demonstrated willingness to come in and do buybacks. In fact, when I come in people are still closing their books for 2020, but when I come in and see the amount of buybacks done by our midstream peers, I really only see two midstream companies that beat us on the amount of buybacks that were done. We've shown a willingness to do that, as long as we can come in and do it at levels that provide us attractive cash flow yield. As I look at this, it's kind of amazing. The products we handle are basically the building blocks for how we live, the modern way we live. Ethane goes into a Petrochemical plant, and it becomes ethylene, and then it becomes food packaging. How could you live without that? You just go across the board, propane, and Randy talked about it yesterday, but for cooking and heating. What we're seeing is more and more what Tony Chovanec calls sticky demand. You got some numbers on that, I think, didn't you? What were the numbers you put together, Randy? Well, on some of what we were seeing on the sticky demand, we heard yesterday what I think demand for propane in India was approaching 900,000 bpd, and almost 90% of that is for human need. I think that was up 10% year-over-year. Again, that's only 50% market penetration of getting LPG in the households in India. Then you look at the PPE, That's from polypropylene. You take butanes, and we have our PDH and our splitters. We're a player in propylene. Butanes, we have our iBDH, our octane enhancement. Those are fuel additives, lubricants. What comes across to me, and when I was in the chemical business, we always said ethylene was the building block for plastics. NGLs and crude oil, and that's the building block for ethylene and propylene. Right. Which then creates how we live. Mm-hmm. Again, your experience, especially as a Dow retiree, when it dawned on me just how prevalent organic chemicals were in pharmaceuticals, Jim was like, "Well, that's no big deal. Dow used to own an aspirin company. Of course, you've got organic chemicals in pharmaceuticals and aspirin and what have you." Most recently, there was an article that was talking about in the COVID vaccines. It was talking about, I guess, the vehicle, the medium of delivering the vaccine was polyethylene glycol, which is, again, a Petrochemical product. Again, I think we underestimate how prevalent products from oil, natural gas, and natural gas liquids are in our lives. What is it Tony? I think he said it in his presentation, or he will say it. I'll take some of his credit. 60% of the growth in crude demand will be petrochemicals. Right. When people say, "Well, where are you going?" Well, hell, if 60% of the demand growth is petrochemicals, where do you want to be? Yeah. I want to be where the demand growth is. I think the one last thing to hit on this slide is you see we have volume numbers. That's what I wanted to talk about. Yeah. Yeah. Yeah, we have volume numbers of how much of this product that we handle. This picks up not only the transportation, but it also picks up, it could be picking up transportation of mixed NGLs, the fractionation of mixed NGLs, and then the delivery of the product. If you think about ethane, we're picking it up really 3x, or 4x as we touch it in mixed NGLs. As we transport, it goes through the fractionator, then it either goes in a pipeline, or it gets loaded onto a ship. When we come in, and we did that for each of these products that we handle, when you come in and you look at it, in total, we handle, oh, gee whiz, approaching 15 MMbpd of oil equivalent product. When we come in and look at this natural gas and then ethane and propane and the butanes that are used for petrochemicals or used for human need probably make up about 70% of the volumes that we handle. Again, a lot of what we handle is directed in that area where, one, I think it's consistent with energy evolution, but it also comes back in and picks up what Jim talked about, that with the demand for petrochemicals growing at that 1.3x, 1.4x, 1.5x multiple to GDP. We like where we're positioned. Today, I guess, they're going to hear from Tony again, speaking about fundamentals. Then I think they're going to hear from Brent Secrest and his team. Right. Chris will come back on and hit finance. Do the financials. Write your questions down. We're going to have a call-in question- and- answer thing. It's going to be kind of like an earnings call, I guess. Right. Write your questions down because we're not afraid of them, and you may not like the answer, but we'll give an answer. You may like the answer, who knows? I think you can tell, and I hope you can tell from the folks that speak to you today that we got a company that we're driven to sustain it for 100 years. It'll evolve, but there will be an Enterprise. That's my goal. Thank you very much. We appreciate it. Our next discussion today will be from Tony Chovanec to talk about supply and demand fundamentals. Well, welcome to the fundamentals portion of our 2021 analyst presentation. Yesterday, we covered ES&G topics. Today we'll be discussing more traditional fundamentals, including our production forecast. Now, first three slides, we cover our production scenarios. This year, we're again showing two cases. We consider the low case to be about a $45 oil case, and the high case would be something probably around $55. Looking at 2021, public producers have said that they planned to exit 2021 with production roughly flat to where they exited 2020. With the higher prices and the recent steady increases we've seen in rigs and frac crews, that certainly appears achievable. Generally speaking, our high case assumes activity gradually increases, returning to roughly pre-COVID levels by mid-2023 in the Permian and in the Eagle Ford, and 2/3 of that level in the other plays. In the low case, which frankly is appearing more and more academic by the day, activity only returns to about 2/3 of pre-COVID levels in the Permian and in the Eagle Ford, and about half of pre-COVID levels in other plays. In both the cases, the Permian dominates. Getting into a few more details, the high case shows about 13.5 MMbbl of production of oil in 2025. The low case shows about 11.5 MMbbl in that same timeframe. The low case we show as a dashed line because we believe it's hard for global fundamentals to justify those fall numbers out of the United States. Likewise, we show NGLs growing to slightly more than 7 MMbpd by 2025. In even the low case, it's over 6 MMbpd. We show natural gas in the high case approaching 100 Bcf a day. I also want to take a minute and talk about federal acreage. It's only been a few weeks since the Biden administration issued a temporary ban on permits on federal land. There's a lot of uncertainty about ultimately what's going to happen. All of that said, when you look at the size of the Permian Basin at approximately 15 million acres, about 12% of that's on federal land. On that federal land, there are currently 2,000 active permits, probably more, and 600 or so DUCs. Producers have been telling us that they have enough permits to drill for four years or more. While none of us can be happy about the administration's position, it certainly appears that Permian producers have been preparing for its potential. I also want to take a minute and discuss what we've been seeing relative to the staying power of NGLs. Remember that 60% of our NGLs are associated with oil production. On the surface, one would think that production rises and falls in lockstep. We've always known that that's not true, I think the recent downturn really proved it when as rig counts fell, producers were saying the gas just keeps coming. We expected it to keep coming, but the magnitude of its staying power, especially in the Permian Basin, somewhat surprised even our supply appraisal folks. This graph shows that while production over the last 12 months was down 13% for oil, gas production was only down 4%, and natural gas liquids were actually up 7%. You would expect, there's more than one reason for this phenomenon, the biggest reason over time is the GOR actually rises in a typical oil well as they deplete. As I said before, while the impact of these ratios is often masked during times of rapid growth, it becomes acutely apparent when oil production actually falls like it did in 2020. We saw this in 2016, not to the magnitude that we saw in 2020, because the production downturn wasn't as large, it wasn't as sudden, and it was relatively short-lived. There were a few other reasons that caused these ratios to move up, including significant reduced flaring of very rich gas in the Permian and Bakken, which we think amounted to as much as $550 million a day. Somewhat higher ethane recoveries also played a role, to some extent, more efficient, newer processing plants. No, it wasn't a new production technique or different rock. It's just the rock doing what it does, and for someone like Enterprise Products, that's not necessarily a bad thing. On this next slide, we've taken a simplified, but we believe directionally correct look at the U.S. producer cash flow potential. We start with the assumption that at $45 a barrel, U.S. producers are cash flow neutral at the company level, which is what we estimate from their comments and comments we read in the Dallas Fed Energy Survey. From there, we calculate incremental cash flow potential in $5 increments, assuming they net about 66% of every incremental revenue dollar. Frankly, the cash flow upside for the industry at $65 oil is an impressive $50 billion a year. Data shows that the oil and gas industry has about $100 billion of high yield debt due between now and 2026, excluding debts that's in the deeply distressed category. While admittedly the calculus is very different at $35, at $60 a barrel, it appears to us that this is an industry that can comfortably self-finance and pay down its debt. Jim thinks the $60 benchmark is low. Six weeks ago, I'd have told you I thought it was high. It's really hard to deny the trend is bullish for a lot of reasons. I want to talk about those reasons next. We believe the fundamentals still lean bullish in spite of the fact that the WTI price has already moved up from $45 to greater than $55 just since the first of the year. We're not alone. Virtually all banks and energy analysts are predicting higher prices than the current forward curves. Bullish drivers include OPEC+ remains disciplined and focused on stability in the markets. The World Bank paints a pretty ugly picture for virtually all of OPEC's budgets again in 2021. From looking at those numbers, it doesn't appear they can afford another price war. Next is the recent approximately 30% reduction in spending worldwide on oil and gas. Some of this appears to be permanent. Meanwhile, the United States has the world's only short cycle reserves, and we don't believe that non-OPEC supply is going to rebound without a very strong price signal. What's the number where U.S. producers are going to crank it up? What does crank it up mean? Obviously, we haven't found that yet, but oil drilling and completion activity continues to rise. This next graph, we look at global inventories. It shows that global inventories peaked at about 3.5 Bbbl of crude and product in June of 2020. If we go back to 2019, we believe a normal level is about 3 Bbbl. By the end of 2020, we believe global inventories had fallen to about 3.2 Bbbl. We and others think that by the end of the first quarter, or maybe sometime in the second quarter, those numbers will drop to about 3 Bbbl. There are a lot of variables, but if we model in OPEC plan cuts, our balances show that sometimes in the second quarter, global balances will begin to shrink towards uncomfortable levels. Obviously, OPEC would step in before that would happen. Frankly, that's what we think is going to happen. Given their commitment to discipline, we don't believe the U.S. producer's going to do it, at least not the publics, and not in 2021. Where could we be wrong? A lot of places, including significant and lower demand. The case numbers and vaccinations, at least in the industrialized world, are pointing to some pretty positive trends. Frankly, at some point, demand could actually surprise to the upside. Otherwise, we all know that OPEC can always surprise. Like I said before, we believe that they don't want another price war. This concludes my market fundamentals comments for today. I sincerely always look forward to your questions and commentary. Thank you. Thank you, Tony. Next up is a commercial update headed by Brent Secrest. Good morning, everyone. I'm Brent Secrest, the Chief Commercial Officer at Enterprise Products, and I'm joined this morning by the department heads for each of our business units. To my left is Natalie Gayden, who has commercial responsibility for natural gas. Tug Hanley, who is responsible for our regulated assets. Brad Motal, who is over crude oil and natural gas liquids, and Chris D'Anna, who is responsible for our Petrochemical division. You will hear from each of these individuals in a little bit as they provide an overview of their business and discuss the sustainability of our cash flows. All of you are familiar with this map. You have heard us talk over the years about having a fully integrated system. There are no one-off assets. Virtually everything is connected to something that goes further downstream until it gets to the water, a refiner, a Petrochemical facility, or another end user. By starting with the highest sales price and leveraging that through our assets, we are able to maintain volumes and margins throughout the system. What this map also depicts is a series of very valuable options. These options allow us to move hydrocarbons to the most valuable location, to upgrade hydrocarbons into more valuable products, and to store these hydrocarbons to take advantage of a premium price at a different point in time. The value of options are time and volatility. You have heard us say in the past that we embrace volatility here at Enterprise, and the volatility in the market this past year and the flexibility of our assets is what allowed us to have such a strong 2020 in an industry that was brought to its knees by the sudden demand destruction. Dan Duncan always said that the more molecules you touch, the more opportunity you have to make money. This asset footprint is what allows us to achieve and maintain the volumes we have through even the most vicious of cycles. I included this picture because it embodies something else that I think is important when it comes to sustainability. As you can see, this picture was taken on April 20th, when crude oil had a historic day and traded levels never seen before and levels we will probably never see again. I think this photo exemplifies our culture at Enterprise. I recognize the fact that nobody has a mask on, and we may not be exactly 6 ft apart, but keep in mind that the city's mask order had not happened, and it was the following week that we mandated mask-wearing as a company, prior to the city's requirement. I think, or it sure felt like, we were the only company with employees at an office in downtown Houston, and some days it still feels that way. What happened leading up to that photo was the essence of Enterprise, a culture of teamwork and creativity always wins. It was people working together to find as much storage that we possibly could by deferring tank cleanings or moving other products around to accommodate crude oil. It was the strategic reversal of pipelines to deliver discounted crude to markets that were still buying. It was an open, in-person dialogue between commercial distribution and operations that led to the addition of millions of barrels of capacity to capitalize on this unprecedented opportunity in the market. There is always a way to get things done at Enterprise if you have focus, you are willing to work hard, and you embrace a culture that never accepts no for an answer. Our culture started with Dan Duncan and has been sustained as it is passed down from generation to generation at Enterprise. It is in our DNA. Everyone wants to know how Enterprise will survive this graph. Regardless of the midstream service, assets are overbuilt and have excess capacity. That excess capacity will get rationalized over time. Inefficient assets are either shut down or they are repurposed. This includes both non-integrated assets and assets that don't have properly structured long-term contracts. These are the first assets that become exposed and will be the first to be removed from service. You have heard from Tony and others about drilling rates, and the fact is, it will take time before production starts growing again. In the near term, producers will be more disciplined and work to get their balance sheets in order, but price has a way of fixing things. At some point, prices will incentivize growth in production to satisfy global demand. Time is on our side, but in the meantime, we will be doing everything we can to be more competitive and force rationalization. How do we survive this graph? Natalie Gayden is going to talk to you about how acreage dedications in the right areas with reliable producers, combined with a large percentage of MVCs, will get the gas business through this trough. Tug Hanley will speak about the durability of throughput on interstate pipelines and speak to our history of repurposing assets. We won't get into specifics of what we are looking to do, but we have a successful track record of reacting to markets and we have an asset footprint that is second to none. One thing we can all agree on. The value of pipelines and the barrier of entry to construct those pipelines goes up every day. Brad Motal will speak to you about the take-or-pay contract mix we have in crude oil and NGLs, and the enhanced value of those assets due to the markets they service. Chris D'Anna will discuss our Petrochemical business and the longevity we see in this space, and the reason we have shifted nearly 70% of all of our currently planned CapEx into this business. Natalie, why don't you go ahead and start us up in the various basins, and we'll work our way downstream from there. Thank you for joining us today. I have responsibility for Natural Gas business development here at Enterprise. I get to go first today because my business typically has one of the first touches on the energy molecule. It won't be the last. My goal is to illustrate a couple of topics that Brent briefly mentioned. Before I start, I want to ensure you know what our Commercial teams really do. We fill assets and maximize corporate operating margin. While I have responsibility for a business unit, don't think for a second that when Brad is meeting with a producer to discuss fractionation, he's not thinking or mentioning gathering and processing opportunities. The same holds true in natural gas. When we meet with producers, we aim to connect them with every part of the integrated value chain, whether it be condensate handling or fractionation from third-party processing plants. We have no boundaries, especially Tug. He's been known to verbalize the sharpest G&P rate seen in the basin to win over a pipeline transport deal. That's okay. We're a team. The map you see before you represents our natural gas standalone assets. It does a good job of highlighting our gas footprint. More so, it does an even better job of illustrating what basins we did not establish a natural gas footprint in. We have 21 natural gas processing facilities and over 19,000 mi of natural gas pipelines. In liquid-rich basins, we operate NGL downstream infrastructure such as pipelines, fractionators, export docks, pet chem facilities, and the list goes on. In dry gas basins such as the Haynesville, we compress, dehy, treat, and transport gas to end users. What I'm really trying to say is our business model is the same in both lean and rich basins. Touch the molecule more than once, create systems, not silos, and leverage the value chain to maximize operating margin. During troughs, inefficient assets get exposed. Where we are able to capture the same revenue with less expense, operating margin increases. An ongoing exercise likely happening, or quite frankly, should be happening, in every business and every company and space of this industry, is rationalization of assets. One of those things is right-sizing our gas processing footprint to current production levels and shutting down gas processing plants that are inefficient for the existing production. When you look at this map, facilities that will or already have been idled this year are circled. We are removing 1.1 Bcf a day from our gas processing stack. Over $20 million per year of expenses saved. This isn't a new exercise to us. All of the processing facilities in gray represent assets we have idled some time in the past. Until production justifies the need to operate these plants again, they will remain idle. You might believe that by idling upstream assets, we are losing somewhere downstream. We're not. In 2020, a year that I'm not sure can be replicated, we saw NGL production 3% higher than 2019 from our gas processing plants, and we expect increases to continue. If I could have got the elephant in the room picture on this slide, I would have, because this is the Delaware Basin processing version of the elephant. As you can see in the chart on the right, Delaware processing is currently overbuilt. When demand dropped due to the pandemic outbreak in March, rig activity came to what felt like a screeching halt. Reduced production left some processing plants empty. While rig count is slowly improving, as you can see on the chart to the left, we don't believe it will be enough to fill plant capacity, at least not right away. The total Delaware basin, for example, is operating at 75% utilization today. Any processing facilities running greater than 75% capacity are doing better than the total basin. You might ask how our plants are holding up. As you can see on the chart to the left, our plants averaged 1.5 Bcf a day in December. That's 94% of nameplate, I would say pretty good. We have new contract volumes ramping this year, that's great for us. The story I'm going to share with you next about what we've done over the last year to de-risk this overbuild issue for Enterprise G&P in the Delaware, we're pretty excited about. This industry understood a new phrase in 2020 called discretionary acreage. What I mean by that is you can have the largest, most profound acreage dedication with the biggest, most credit-worthy producer. When that producer's capital deployment for the year gets constrained to longer cycle investments, not necessarily investments with greater return, you realize how valuable getting a take or pay in a short cycle shale play is. In this slide, I want to emphasize two things. Number one, we will get paid. Over 70% of our nameplate capacity is take or pay volume with investment-grade producers past 2028. That has increased significantly since 2019. Number two, the integrated value chain leveraged this assurance. We've always said that we use the value chain to benefit the whole, and this was an example of that in action. No producer comes to the table asking for a take or pay on gathering and processing. Last year, when one of our customers came to the table asking for other things within the value chain, we used the opportunity to yield a win-win. We got a take or pay, kept an acreage dedication, and the producer was able to right-size an obligation they had to us in a different business unit to match their changing production profile. We like a little exposure to the private guys. You can see in the chart to the left, private operators make up 40% of the rig activity in the Delaware. Our exposure to privately operated production lies within our acreage dedications, and they make up about 30% of that volume. We get a lot of questions about the effects of frac ban and new executive orders on gathering and processing business in the Permian. To be quite frank, this is why you don't hear a whole lot of panic in our voice. Finally, this presentation would not be complete without talking about our most recent capital projects in natural gas. While some folks might have been spending their time and money investing in west-to-east takeaway, but not landing at the real demand center, we spent ours contracting a pipe to an export hub. You'll hear it mentioned a couple of times today that we fundamentally believe for all commodities, transporting to the right demand centers and originating from low-cost producing areas is the key to cash flow longevity for pipelines. The overarching topic this slide really displays is one of disciplined, calculated investment and backstopping an investment with long-term take or pays. As you can see on the top right, the Haynesville was the first basin, I think still the only basin, to restore drilling activity to pre-pandemic levels. Comparatively strong well economics, I mean, these guys tout six to 18-month returns depending on the acreage, paired with close access to a premium Gulf Coast market makes the Haynesville a lean gas basin to compete with. Last year, we brought on what we call our Carthage mainline. It's a pipeline backed by 10-year take or pay contracts and gathers lean gas from this low-cost producing resource. Gillis is no different. Remember, Gillis is an 80 mi extension of our Acadian Haynesville pipeline, and it will transport gas to a growing LNG export hub. This pipeline is also backed by 10-year 100% take or pay contracts. These projects made sense for our business model. If you hear nothing else from my presentation today, note these three things about our Natural Gas business. Number one, we're in the right basins. Number two, we have the right mix of take or pay contracts with investment-grade counterparties. Lastly, we do take our customers to destinations that provide them the best net back for their product. With that, it makes most sense for Tug's story to follow mine, since he's the next critical link in the Enterprise value chain with an NGL pipeline for every Enterprise gas plant. All right. Thank you, Natalie. This is our interstate pipeline map. Spans over 27 states. We transport over 4 MMbpd. If you look at this pipeline map, look at the integration, and appreciate that some of these pipelines can never be replicated in the future, you can see there are a lot of opportunities, some of which may be a fundamental change in the operation of the pipeline. I'm not sure if this network of pipelines start and end in the right place or if the assets are in the right service. I have no idea where they're going to start or end when we talk next year. It may be different, and that is the great thing about how flexible these assets can be. Stay tuned. With that, I would like to take the opportunity to show you how resilient these assets and the markets they served were in 2020. If you could imagine the worst thing that could happen for TE Products, 2020 was more impactful than anything I could have imagined. TE Products is a downstream-oriented pipeline. The outlook at the start of the pandemic was less than optimistic. How wrong we were. TE Products is a story of resilient demand, connectivity to the most economic refineries, which are located in the Gulf Coast. What we saw in 2020 was refinery utilization was lower in the Northeast versus their more economic counterparts in the Gulf Coast. Products and propane demand that was traditionally satisfied by the Northeast refineries now need to be satisfied by TE Products. If you look at the graph on the left, for the entire year of 2020, our TE Products throughput was only down just 10%. If you look at 4Q of 2020, throughput started to exceed our pre-COVID and historical throughput trends. In fact, it started to set historical records on ULSD, jet, and diluent. This is due in part because the less economic refineries in PADD 1 continued to remain underutilized versus their Gulf Coast counterparts. Our jet transportations year-over-year were largely immune to COVID demand destruction as we supply Tier 1 logistics providers who make it possible for all of us to have packages on our door every day. propane was a much better story. Our propane customers are comprised of agricultural, industrial, residential, and home heating markets, all who continued to use product through the pandemic. Total propane demand was slightly down due to warmer weather in 2020. However, with less regional supply from the PADD 1 refinery complex, our long-haul propane movements were significantly up year-over-year. They increased by over 200%. As we stand here today, we are loading record volumes of propane through our MidCon, Southeast, and Northeast assets. The value of interstate pipelines that are demand-centric go up in a declining supply environment. Displacement and rationalization of supply to more economic parties further away is not a bad thing for interstate pipelines. 2020 reinforced this. Let's move to ATEX. ATEX continues to perform. Let's call the Marcellus- Utica pandemic-proof production relative to other basins. The Marcellus- Utica had stable production in 2020, and we expect it to continue to do so in the future. We have been successful in adding new long-term contracts on ATEX because our customers desire having market choices and reliable takeaway. ATEX allows our customers access to the ultimate demand center in the Gulf Coast, where they have multiple market choices, exports, Petrochemical, storage, the list goes on. It is not limited to one single market. We look forward to our expansion coming online in the second quarter of 2022, again, backed by long-term take-or-pay contracts. ATEX is another example of an irreplaceable asset in our portfolio. Looking at the graph to the left, you can see it is fully contracted with take or pay with term beyond 2030. Next, let's talk about the ultimate demand center. Aegis supplies the U.S. Gulf Coast Petrochemical complex with critical feedstock. This is extremely durable demand. These are the companies that allow us to enjoy the high standard of living we can appreciate in our daily lives. They make the face masks that we have been wearing possible, down to every component in consumer products. Chris D'Anna will talk more about that later. We have an 80,000 bpd expansion of this pipeline coming online next month, backed by long-term take-or-pay contracts. We also have recently agreed to extensions with our existing customers past 2030. Both ATEX and Aegis are very high barrier to entry assets, fully contracted long-term. Let's move to our supply-oriented assets. Having an integrated system allowed us to be successful in maintaining and growing our waterborne volumes in 2020. Diversity and access to multiple basins was key. None of our assets are a one-trick pony that go from A to B. On the demand-centric assets, our customers value market choices. It is no different here. Despite the story of U.S. crude production being down in 2020, U.S. NGL production was up 1% year-over-year, and our volumes performed even better. We are up 8% year-over-year on our Western region assets. You heard Natalie earlier talk about her inlet volumes going up, and we have a lot to thank her team for our volume growth. We continue to be successful in executing third-party connections and contracts as well. We will be bringing several new connections with additional volume online in the second quarter of this year. You can't talk about supply without mentioning Seaway. The Canadian producer makes a very desirable barrel for the economically advantaged refineries in the Gulf Coast. We have great alignment with our joint venture partner on Seaway, and together offer a producer a path from Canada to the water. While utilization has nearly returned to pre-COVID levels, it looks different. We are seeing a lot more heavy versus light crude on Seaway. Seaway is benefiting from this change in product slate due to transportation rates on heavy commanding a premium to light. We are also seeing heavy export growth, which we traditionally have not seen in the past. With the improvement of utilization, we have increased our market-based rates on Seaway month-over-month in the first quarter and expect to do so until we have reached full capacity. With the alignment with our partner, the existing contracts we have on Seaway, and the ability for a low-cost expansion in the future, the outlook on Seaway is positive. Thank you for taking the time to hear how resilient our assets were in the markets they served in 2020. I will finish where I started. Brent mentioned earlier of assets being overbuilt and underutilized, and this is something we have been faced with in the past. Seaway was once underutilized. The ATEX pipeline that was part of TE Products was once underutilized. Both have been repurposed and stand fully contracted today. In the case of ATEX, repurposing the asset also increased the value of the segment of TE Products still transporting volumes north. With our footprint, our integration, and our value chain, we have an energy platform that will lead to future repurposing opportunities. If you look at our history of repurposing of assets, pipelines have changed the direction they flow, and some have completely changed the service they were once in. I look at storage as one of our most versatile assets. Our ability and history of changing the products that are in salt dome storage caverns to capture the best opportunity has been very, very lucrative to us. Just because a business unit has a certain asset in their portfolio today doesn't mean it will be there tomorrow. These are Enterprise's assets, and they will be used for a purpose that makes the most sense for Enterprise. You know, Brent, my groups have benefited from several of these repurposing efforts, and I'll touch on some of them briefly as I discuss our unregulated NGL business as well as our Crude Oil businesses here at Enterprise. Over the next few minutes, you'll hear how our integrated business model drives our contract strategy across these business segments and the value and the stability created by demand-based agreements. As you know, in years past, many Analyst Day presentations, ours included, talked about projects that were commercially contracted, constructed, and placed into service in the prior year. Frankly, in certain years, our new project inventory was criticized for being lower than others in the midstream space. My, how things have changed. We thought we would take a different approach this year, as 2020 was not a normal year. Last year was a year that our DNA and culture paid dividends or, in our case, distributions. Anyway, we pivoted quickly from our normal growth mode to one where we took a hard look and necessity to build new capacity, even when those facilities were supported by contracts. Unlike others, we do not build things just to build things. Throughout the year, our Commercial teams worked to evaluate the true need for these expansions and analyzed our ability to perform our obligations within our existing asset base. We talked with our customers about their changing needs and understood that customers might need less capacity than they first anticipated back when the deal was executed. We discussed how we could assist them during these challenging business environments. The rationalization of our asset base and these conversations bore fruit for both sides. As you can see in the chart, we had several large-scale projects totaling over a billion and a half dollars that even though we had contracts to support, we had the ability to cancel. What allowed us this flexibility? The answer is pretty simple. Our integrated asset footprint and our contracts. More specifically, our take-or-pay contracts. The symmetry of obligation within a long-term demand-based agreement creates an environment where both parties' obligations are plainly stated and lends itself to find creative solutions. Over the course of 2020, the Enterprise team executed multiple contractual modifications across its business units that enhanced our operating flexibility while extending term and preserving the underlying economics. The common theme in many of these modifications was an underlying take-or-pay agreement. What drives our ability to contract large portions of our portfolio on take-or-pay agreements? I say it's our ability to perform and the markets that we access. With three pipelines, including a repurposed NGL pipeline that has over 1.3 MMbpd of pipeline capacity going to a market that has depth and optionality, both domestically and globally, our customers see the value our system provides and have been willing to make firm revenue commitments to ensure themselves a reliable path to a liquid market, to Houston. Customers see the value in going to Houston, a market that has a multitude of refining customers, hundreds of millions of barrels of storage, and export options. It is not a dead end at the beach. These organizations entrust Enterprise to make sure their barrels move every day and make delivery where and when they need them around the city of Houston. As you can see in the chart in the top right, as the rig count collapsed throughout the year, our customers' volumes moved on the Midland-to-ECHO pipeline system not only survived but thrived as we brought our third pipeline into service in the latter part of 2020. As Brent mentioned in his opening, the midstream space is overbuilt and will be that way for the near future. Nevertheless, the contracts we have executed provide a bridge to better days ahead. Looking at the chart, Enterprise built the Midland-to-ECHO system for the long term. We hold contracts that effectively fill our pipeline to its optimal capacity of 1 MMbpd beyond the year 2028. 85% of our take-or-pay agreements are with investment-grade counterparties, and many of our pipeline customers have additional downstream contracts with us. The pipeline is just the first in a suite of agreements providing us with multiple revenue sources. Looking at our crude dock activity for 2020, our crude dock business continues to provide cash flow stability via our take-or-pay contracts, again, with investment-grade counterparties. Dock volumes dropped by roughly 40% throughout last year, but revenues remained stable. In addition, this cash flow stability carries forward. The duration of our agreements vary. However, on average, the contract term is around eight years, and in many cases, our dock commitments align in term with our customer commitments on the Midland-to-ECHO system. One last thing I'd like to point out here. I think this slide highlights Houston as a market. Houston is not the home of forced exports. Our customers have a choice. With the export arm remaining closed most of 2020, our customers chose to sell their production domestically to achieve a higher netback price versus the waterborne price. Oil consistently moved to Houston on our pipelines but was not consistently moved across the dock because it was not forced to leave. Because it had a choice. In the past, we have said we are always looking for partners where it makes sense. To Enterprise, it makes absolute sense to collaborate with Magellan to develop a new futures contract physically settled on the Gulf Coast, home of the largest, most integrated refineries in the United States. It is our belief that the combined effort will create a contract that has greater transparency and reflects the market depth, liquidity, and optionality only Houston can provide. As the refining sector rationalizes its capacity and facilities idle, the refineries along the Gulf Coast will remain the foundation for that sector's production capabilities. To that point, we believe a price marker for U.S. crude should be more aligned with the physical flow of barrels and priced on the ultimate destination, and not priced off a rest stop on the way to get there. This new contract will be for a premium-source WTI barrel and provide for physical delivery at either ECHO or MEH Terminal, with consistent quality being a key focus. We believe that the success of this effort will enhance the value of our assets and draw barrels to our system over the long term. Looking forward, the development of this contract will also play a complementary role in not only our existing export facilities, but as well as our SPOT project. We believe that it will provide international customers with direct access to supply, market efficiency, and simplification of their hedging efforts. At Enterprise, we remain committed to building SPOT. We continue to work towards the record of decision and receipt of our license later this year. We look forward to taking the next steps in the process. At the beginning of this presentation, we described our asset map as a giant set of options based off flexibility and optimization. At Enterprise, our NGL business is at the heart of all of our optimization efforts. It is the poster child for how we do things across the entire organization. Our NGL assets provide reliability and flexibility that our customers require and provide them direct access to the ultimate market for NGLs, Mont Belvieu, Texas. At Mont Belvieu, Enterprise is the pricing point for those NGLs, which gives our customers added optionality and liquidity and acts to draw barrels towards our system. Our connectivity is second to none. We receive or deliver NGLs to 37 refineries and 34 chemical facilities across the country and provide NGLs globally via the world's largest LPG export facilities. We operate our 17 fractionators and approximately 200 MMbbl of storage as a super system, with Belvieu being the focal point. As we need, we can flex volumes to our regional fracs in South Texas and Louisiana, providing us with the ability to remain aggressive to new supply opportunities. Conversely, we will rationalize our fractionators and high-grade throughput to the most efficient facilities during periods of lower production. Over the last year, we've idled two of our less efficient fracs. We recently idled our Armstrong frac in South Texas, working with operations and the natural gas group to move these barrels to Belvieu while maintaining our contractual obligation for Armstrong's production. We completed the same exercise of our Tebone facility over in Louisiana in early 2020. Our fractionation business remains largely contracted on a take-or-pay basis, though we adapt to market changes. We have added select plant and acreage dedications to our portfolio. The structure of these agreements provide our customers with the flow assurance they desire while giving Enterprise the flexibility to optimize its daily obligations across the asset base and continue adding new customers. I would not do our NGL system justice if I did not hit at the true heart of our flexibility, our storage capabilities. The storage caverns are the foundation upon which our system's flexibility is built. It's not just that our storage position is one of, if not the largest in the world, it's the ability to move different products into different wells of different size, having different flow rates that truly maximizes a given opportunity. The ability to stage barrels at key locations, hold them, and move them at high rates underwrites the options our system provides us. The cavern allows our customers to ensure feedstock supply and allows our asset team to manage frac inlet rates to maintain optimal throughput levels. I like to think of storage as a giant shock absorber that absorbs the disruptions in the supply-demand equation. Across our system every day, some producing customers over-deliver and some under-deliver, pipelines slow down or have maintenance and stop completely. On the other side of the equation, consuming markets may take more or less than their anticipated volume. Nothing is ever perfectly balanced. It is the storage caverns that make all the difference. Lastly, I will speak to our LPG export business. Similar to our Pipeline business, we are able to contract our dock capacity on a take-or-pay basis. Unlike some of our other business segments, our export customers prefer higher levels of optionality by way of shorter contract duration. That fact doesn't concern us. If I were to rank our businesses by recontracting risk, the LPG export business would be at or near the bottom of that list. In this chart, we look back at the contract roll-off in 2015, showing the short-term nature of contracting in this business. We have expanded twice since 2015. You can see that our contract roll-off looking forward in the lighter blue. If we looked at this chart next year, 2023 and 2024 bars would grow to fill the capacity as we execute new contracts. The export business is a hamster wheel, and we're always working to extend contracts, execute SPOT opportunities, and broaden our customer base. As we think about the future of our LPG business, we know the world will continue to come to the U.S. for barrels. LPG will price itself to export with over 50% of the propane produced daily in the U.S. needing to move across the dock. We cannot keep it here, and we shouldn't want to keep it here. U.S. LPG allows emerging markets to transition from surviving to thriving, and we at Enterprise are proud of our role in helping raise the standard of living for millions around the world. Now I'll turn it over to Chris to talk about our Petrochemicals business. Thanks, Brad. petrochemicals story is much different from what you just heard from Natalie, Tug, and Brad. What you just heard from Brad is how we create win-wins by not building assets. I'm going to talk about how we're creating win-wins by growing our business and expanding our systems. The Petrochemical business is a story of growth and opportunity. I'm going to spend some time talking about why we have this business and what it does for us. This business makes us unique in the midstream space, and it's a competitive advantage. Earlier, Tony Chovanec addressed the importance of petrochemicals in a growing global population. Ethylene and propylene are essential to building the products that are needed to raise the quality of life for the world's growing middle class. Products like paint and coatings, electronics, medical devices, PPE, mattresses and furniture, carpet, appliances, cars, and many, many others. You can see in the chart on the lower left, the growth of ethylene and propylene has been at multiples to GDP over the last 10 years. The reality is, you can go back further and the story is the same. If you think about it makes sense that the demand for ethylene and propylene is higher than GDP, as the growing middle class buys more of the things that we have grown accustomed to here in the U.S. The growth story is one of the reasons we like this business. We also see an opportunity to further commoditize primary petrochemicals. Ethylene and propylene are commodities, but their markets do not function as mature markets. We see a great opportunity to help further accelerate market development through our market hubs and export terminals. We like this business because of the growth, but we also like it because of the integration and the fit to the company's value chain. We talk about our integrated value chain, and you can see in the picture on the bottom center, our Petrochemical value chain and how it fits with the rest of Enterprise. The feedstock for our Petrochemical assets either originate from our upstream assets or from customers of our upstream assets. For example, propane from our fracs feeds our PDH. Our fracs feed ethane to the crackers that supply ethylene to our pipeline storage and export terminal. We provide crude to the refineries that supply refinery propylene to our splitters. This means that the relationships that we have with our customers become much larger because the services we provide are expanded beyond what a typical midstream company can provide. It's not obvious, but there's also significant integration between our assets. For example, our octane enhancement plant and i BDH create RGP that's fed to our splitters. Our PDH plant creates some of the feedstocks for our octane enhancement plants. These are just a few of the examples of integration within our system, but there are many more. We continue to develop projects that add to this integration. The Pet Chem & R efined Product segment made up 13% of Enterprise's GOM last year, but it makes up 68% of our capital projects under construction. I'll talk about several of our projects and our systems in more detail, but one thing you'll note, all of our projects create assets that have a high barrier of entry, are world-scale in size, provide supply to our system, and allow access to demand, including demand in other parts of the world. There was a point in time where we had a closed propylene system, operating in a Hotel California mindset, meaning we only used our system for our own sales and didn't allow others to use it. We didn't embrace our midstream service provider mindset, but not anymore. Now our system is completely open. Anybody can participate. We believe that creating a robust hub is one of the most important things we can do to further enable fast, efficient growth in ethylene and propylene markets. Our hubs connect supply with demand. When a producer makes extra product, there's always a buyer in a hub, and the same is true when a consumer needs supply. Hubs enable efficient price discovery, and through their connectivity, make sure that the product finds the demand point dictated by the market. We know what a successful hub and market look like. We've done this before in NGLs and in crude. 20 years ago, the NGL markets functioned much like the propylene markets, where contract prices were negotiated between buyers and sellers for a month, for three months, sometimes even a year at a time. These hubs provide our customers and the whole market the opportunity to buy or sell at any point in time. The market sees these prices, which allows it to be much more efficient. We've seen the liquidity in our propylene hub essentially double from 2019 to 2020. So far in 2021, it's on this pace to carry the same growth. This is the reason that buyers and sellers want connectivity to our hub, because the marketplace. Hubs provide the opportunity for marketing optimization. This optimization has provided Enterprise significant value over the years. In 2020 in particular. Our participation in the hub also means that we have a seat at the table for any meaningful growth opportunity. For us, it enables future growth. In fact, when we started developing our ethylene business, the hub and its connectivity to local and global markets was the critical piece that we started with. U.S. ethylene production capacity has grown 65%, as you can see in the chart on the upper left. This production growth was accompanied with very little supporting infrastructure. It was this disconnect between supply growth and infrastructure that motivated us to develop this business. It was this disconnect that allowed us to go from almost nothing to the business we have today in less than three years. It's important to note that we built this entire business as a system. I've already talked about the core of our system, which is our open-access market hub. The hub is currently connected to over 80% of the Gulf Coast third-party pipelines. We're continuing to develop that connectivity today. In fact, we're negotiating contracts right now to further growth in our pipeline system and create additional throughput through our hub. Not only is our system well connected to U.S. markets, we have the largest, most capable ethylene terminal in the world. We finished the last phase of our export terminal construction in December. We've since demonstrated our capabilities to load at almost 3 million lbs an hour. No one else can do this. We've also demonstrated our ability to co-load both ethylene and ethane on the same vessel. This co-loading ability means that our customers can access much lower freight markets than ever before, since larger vessels are used for these co-loads, and larger vessels have a lower per-pound freight rate. This is really a game changer, allowing the Gulf Coast ethylene producers to compete anywhere in the world. While our ethylene system is new, our propylene system has been developed over the last 40 years from a single splitter to the largest system in the world. We have the capability of supplying RGP from our large pipeline gathering system or by barge, rail, truck, and even ships. This means we can access not only local supply, but when the market dictates, we can also access the global market for supply. Following the startup of our second PDH, we'll have over 11 billion lbs of production capacity, which will make us the largest seller of propylene in the world. Not only do we have a pipeline system capable of reaching over 90% of the U.S. propylene consumers, but we also have a PGP terminal with the capacity to export over 3.5 billion lbs per year. Finally, our PGP market hub is the pricing point for ICE and CME propylene futures contracts. The development of our PGP hub has really accelerated over the last year, and now we have connectivity to the vast majority of U.S. PGP producers. Our PGP system is the foundation of our propylene business and serves as the platform for future growth. Finally, I'm going to talk about our PDH 2 project. The construction of our PDH 2 project is progressing very well, and it's on time and on budget. We're building PDH 2 not because we wanted to grow, but because our customers needed the propylene. Our customers need the propylene because the downstream product demand is growing faster than GDP. Remember what I showed you earlier. An on-purpose propylene supply is the only option for filling this demand. Our customers make products used for essential and durable goods, like furniture, PPE, medical supplies, electronics, appliances, and many more. It all ties back to the growing global middle class and producing the products that allow them to improve their standard of living, and that's why our customers were willing to back PDH 2 with long-term commitments. As I already mentioned, projects for the Petrochemical business represent the majority of capital investment for the company in the next few years. These projects will expand our reach via increased connectivity and pipeline extensions, they will provide additional revenue and margin via higher throughput and transportation volumes, and they will enable more fee-based processing. We feel very strongly about the opportunities in the primary Petrochemical space and have several initiatives underway which will create additional growth opportunities and throughput through our system. Some of these are transformational. I look forward to talking about these in more detail at our next Investor Day. What you heard from this group today is that we have a very stable portfolio of long-term take-or-pay contracts. We have interstate pipelines that have a high barrier to entry, and some will never be replicated. We have a Petrochemical business that has a tremendous amount of growth and opportunity. A culture in this company that will help ensure our results are repeatable over time. I am proud to be part of this Enterprise team. Thank you, and we appreciate your time. Our next discussion will be a financial update from Chris Nelly. Before moving on to the financial section, I wanted to take a moment and walk you through how we, from a finance perspective, navigated 2020. We entered the year with $2.5 billion of senior notes maturing. Since it was an election year, we took a risk-off approach to the market and refinanced these maturities early. Enterprise was the first corporate issuer to hit the tape on January the 6th with a $3 billion notes offering. After that, we felt pretty good about our financial position. We declared a distribution increase for February 2020. We bought back $140 million of stock in the first quarter. Came March. The capital markets were sent into a tailspin by the one-two punch of the OPEC price war, coupled with the global demand destruction as the world shut down to mitigate the spread of COVID-19. As Brent and the Commercial group were busy positioning our assets to take advantage of what turned into a super contango environment, we took measures to bolster our balance sheet. Fortunately, our balance sheet was already in a good spot. Our net leverage was at a record low level, 3.25x, and we had $1.4 billion of cash on hand and $5 billion of undrawn credit facilities. Not knowing how long this sudden stop was going to last, we took a page from the 2008 financial crisis playbook and went looking for more liquidity. At this point, fiscal stimulus had not been passed, which led us to our bank capital providers. They stepped up. On April 3rd, we closed on an incremental $1 billion 364-day credit facility, which brought our liquidity position to north of $7 billion. We also withdrew the distribution growth guidance and elected to keep the distribution flat. We paused our buyback program. We worked with our Commercial group to find ways to reduce capital spending. Our mindset was to preserve and protect the balance sheet. We accomplished this by having financial flexibility. Moving on to the slides. This was an interesting slide to put together. In looking back over the past 20 years, the first thing that I realized in looking at these is we clearly don't throw anything away. Beyond that, it demonstrates that we've always been believers in investing in quality, cash-flowing assets with attractive returns, having a strong balance sheet, and returning capital to our investors. We still embrace these same objectives today. To further illustrate the point, if you look back over the last 22 years, Enterprise has, on four separate occasions, taken actions to improve distribution coverage while maintaining distribution growth. While most other midstream companies were taking either an outright or backdoor distribution cut, we not only continued to grow our distribution rate, but we also improved our coverage. Because we went public as a partnership, paying out distributions and returning capital to our investors is in our DNA. Since our IPO, we have paid out nearly $39 billion to common equity holders. If you look at the market cap of those companies in the AMNA index, only three companies have a market cap larger than the amount of capital that we have returned. Yes, Enterprise is one of those three companies. This next slide shows both distributable cash flow and cash flow from operations on a per-unit basis. While distributable cash flow per unit has grown at a 7% compound annual growth rate, and cash flow from operations has grown at a 5% CAGR, for me, when I take a look at this graph, I focus on the three shaded areas. Whether it's a commodity price cycle, financial crisis, or pandemic, macroeconomic events are going to occur. We have investors that rely on our distributions. That is why we continue to believe that it's prudent to maintain ample distribution coverage and a strong balance sheet, or to put it simply, why we want to preserve financial flexibility. The decade following 2010 was a time when the midstream industry saw tremendous growth. Be it the shale revolution, the renaissance of the U.S. Petrochemical industry, global energy demand growth, all of this required a build-out of midstream infrastructure in order to connect these new and growing supply basins to end-use markets. Aside from the year in which we made a material acquisition, our assets continue to generate stable, fee-based cash flows sufficiently covering our new capital investments and resulting in positive free cash flow, especially in the latter half of this decade. As a result of the 2015-2016 commodity price cycle, Enterprise once again took measures to adjust to the changing market conditions and improve our financial metrics. We recognized the need to become less reliant on the equity capital markets. In October 2017, we made the decision to moderate our distribution growth rate. This not only immediately lowered our payout ratio, but we've also not issued external equity since then. Becoming equity self-sufficient was just the first step. The ultimate objective was to become discretionary free cash flow positive. Knowing this was not going to happen overnight, we continued to invest in high-quality, fee-based assets. The cash flow from these investments increased our cash flow from operations by approximately $1.5 billion since 2017. It also reduced our net leverage from a peak of 4.4x in the third quarter of 2016 to 3.5x as it stands today. Managing through this current cycle, we took steps to reduce the overall amount of capital spending. Over the past year, we removed $1.5 billion of projects while meeting the needs of our customers and adding long-term stability to our contract portfolio. As a result, we now expect to be discretionary free cash flow positive by the second half of this year. We continue to take a balanced and disciplined approach to long-term capital allocation. As I mentioned earlier, cash distributions are a part of who we are, and that's not going to change. With respect to growth capital investments, we continue to forecast spending $1.6 billion in 2021 and $800 million in 2022. We do continue to see opportunities for future demand-oriented growth projects that will provide attractive returns on capital. These projects have not been sanctioned and are still under commercial development. No, we don't plan to elaborate on them any further other than to say that they are consistent with an energy evolution theme. Starting in the fourth quarter of 2018, we began buying back our equity. Since then, we have repurchased $312 million of stock at a cash flow from operation yields ranging between 11% and 18%. Relative to our average returns on invested capital for organic projects of 12%-14%, these repurchases were opportunistic. We do recognize that relative to our market cap, $300 million in buybacks is a small amount, but there is a potential for more as we become discretionary free cash flow positive. These next two slides both hit on payout ratio. This first one is EPD-centric and shows that over the past 15 years, we have returned, on average, 70%+ of cash flow from operations to our equity investors, which again, is consistent with our structure, but I would also like to point out that we have demonstrated a willingness to repurchase equity. This second slide then compares EPD's 2020 payout ratio against the various sectors of the S&P 500 and a subset of U.S.-based midstream C-C orps. What is immediately evident in looking at this page is that real estate, energy, and utilities are all capital-intensive industries. The next thing that everyone looks at on this page is our 70% payout ratio. It is worth noting if you adjust our 2020 cash flow from operations for the roughly $770 million in working capital adjustments that we had last year, our adjusted payout ratio for 2020 would have been 61%, or only 4% higher than midstream C-C orps. Let's focus on the gray bars for a second, which is total CapEx. In 2020, Enterprise's allocation to CapEx was the lowest out of all of these capital-intensive industries and significantly lower than our C-C orp midstream peers. Our total CapEx for 2021 is expected to be lower year-over-year by over $1 billion, this weighting will continue to move lower. In keeping with the theme of continuity, once again, we remain committed to building a company that is sustainable for the long term by maintaining financial flexibility, preserving a strong balance sheet, investing in organic growth projects with attractive returns on capital, and responsibly returning capital to our investors through both distributions and buybacks. Thank you for your time today, and as a reminder, we will be holding a question- and- answer call this afternoon at 2:00 P.M. Eastern, 1:00 P.M. Central. Thanks again. That ends our discussion today. Thank you for joining us, and have a good day.