Enterprise Products Partners L.P. (EPD) Earnings Call Transcript & Summary

[Audio Gap] 68 geologists that we didn't know how to use -- and I had somebody from Encana said, you need to put a fundamentals group together. So we had those geologists report to Tony, and then he hired a couple of other people. And we don't have to call IHS anymore to figure out what we believe. We just go to Tony. I think you're going to -- I told Becca, I hope she's good at typing is typically before Analyst Meeting, would have some press releases that we put out. I'm not going to steal your thunder, Brent. Where are you? We have press releases we put out about new projects. And we decided we're not going to put any press releases out. But you're going to hear about a few things that we plan to do. So you probably ought to get your pencil and paper now. Bob Sanders, Becca asked me what Project 11 was. I said it's super-secret. Bob Sanders will let the cat out of the bag. Graham is going to do the -- on engineering operations and supply chain, then I think you're going to enjoy Chris Nelly's panel with Angie and Kerry on evolutionary technology. And then Chris is going to wrap it up with finance. Let's go. Next one. Okay. We had a guy from Washington tell us that we needed to look at things on a 10-year cycle, especially when we visited Washington because that's how they look at things. Now they scored the child tax credit on 1 year and then -- but they say we were told they look. So we decided, let's do 10-year cycles. And when you look at our business or our industry on a 10-year cycle, we entered the decade at over $100 crude oil. We ended the decade at over $100 crude oil -- but we averaged $65, which inherent net is a hell of a lot of volatility. Now in 2008, we were doing 4.8 million barrels a day. We reached to [ 13 ] million barrels a day in 2019. It's an unbelievable story. Natural -- NGLs kind of followed that volatility. Natural gas until recently, it was the most boring hydrocarbon we dealt with. It started the decade at $3 and kind of ended up at $3. We've been giving a gift in this country. It's a gift of natural resources that 15 years ago, we can only dream of. People like George Mitchell, Audrey McLendon, who I loved, I tried to get them 1 time. I told you when we did Apex. I said Audrey you ought to -- Dow will buy this ethane from at a gas-plus basis that time is about $0.50 margin in ethane. And he said are you crazy? I'm making $0.50 a gallon on this stuff. That wave is going to break on the beach, and it did, and he told me later, Tom, I should have done that deal. But these guys in my mind, are heroes. They've given this country a geopolitical weapon that frankly, we don't know how to use. They've brought the price down. And Tony, I think you're going to show this -- the savings to the American people. We produce the cleanest hydrocarbons in the world. I'm looking at -- I have them send me my notes. We produce the cleanest hydrocarbons in the world. Propane -- we make people's lives better. We're the largest producer of propane, largest exporter of propane. And if you look at where it's going, it's going to places that improves the quality of people's lives. We don't get credit for that. It replaces coal, it replaces wood. You are going to talk about how many people die from smoke inhalation. There's 4 million, 5 million people a year that die of smoke inhalation. If you see a picture, I wish we had that slide, Tony. If you see a picture of a household that's burning coal and wood and then compare it to that same household on LPG, it's absolutely amazing what we've done for these people's lives. Let's go to the next one. There's a lot of people that are trying to make us look like tobacco. We've been attacked by environmentalists. We've had litigation. Look at the Mountain Valley pipeline. What is it, 20 miles from being complete and it's caught up in litigation. Keystone, everybody knows about that. Brent is going to talk about the most -- the fact that pipelines that are in the ground are getting more valuable every day. As front row seat. I bet you sat in the front row in school didn't you. Back in '15, OPEC Plus they set out to destroy Shell. They just turn the spicket zone. Yes, I like to tell stories, and I've reached the age that I can say demo anything I want to, and get by with it. So Randy and I, and I think, Tony, were on a call with the U.S. legislator. And we were talking about the Saudis and OPEC+, we were gapping about what they were doing. I mean, crude oil went down to what, $26, Randy? And this guy said, "Hey, look, can I get the Secretary of Energy. Can I tell this story. Can I get the Secretary of Energy on the phone with us, and he's [indiscernible] and we said, sure. So he got on the phone and we started bitching to him. And he said, I talked to the Russian Oil Minister, and he seems to have a sense of urgency about this. Well, that's good. He said, I talked to the Saudi oil minister and he didn't have any urgency at all. I said, well, did you explain to him whose fifth fleet is protecting his -- he said, "no, it's a good point. And he said, "I'm going to see the President this afternoon. I'm going to go there, but I'll point it up. Okay. All right. I'm going to see the President this afternoon. Is there a message you guys would like to give him. I said, yeah tell them to grow some where the Saudis are concerned. I think it's a coincidence, but it wasn't that much longer did he can turn the screws on them. I've never seen negative price crude. So we averaged $65, we went to $100, and we went negative $50 at 1 point in time during the day on April 20. On April 20, 2020, we became so bullish hydrocarbons, that's not funny because we knew people were going to lay down rigs, we knew production was going to fall. Went down to, what, about 9 million barrels a day, Tony, from almost 13. Demand fell off the cliff. And we became extremely bullish because we knew we were going to get through this pandemic. I can tell a story about that, too. I went through Polio and we didn't shut the damn economy down because of a pandemic called Polio, but that's another story. We're back up to 11.5 million barrels a day, Tony, you're going to go through this. You think we'll end the year at 12.5 million. Are you checking to say? Okay. And it will take 8 to 12 months. What's interesting to me now is they're calling people like Mike Worth and Darren Wood and Rick [indiscernible] up in front of a house committee and they're bitching at him to increase production. These were the same people that 6 months ago had him in front of the House Committee bitching at him to cut production. So you probably figure out where my political affiliation lies. That's all I got.

Okay. All right. In coming in and taking a look at what the industry has been through the last 2 years, it's been 2 pretty hard price cycles. The first price cycle was really caused by as Jim pointed out, OPEC+ trying to kill the shale play and declaring a price war on the U.S. industry at the end of 2014, beginning in 2015. And then the second was when the pandemic hit in 2020. So really, when you come in and what we've done here is we looked at the 24 exploration and production constituents companies in the S&P Energy Index. And when you come in and you look at the slide, it really breaks down into 3 phases. From 2012 to 2015, the industry was investing about $160 million a year in E&P activities. And then from that point forward, during the past 4 years, 2016 to 2019, that was cut in half to $80 million a year and then finally, if you come in and you look at the COVID and the COVID aftermath, we've seen that down another 40% down to around $50 million a year. So again, we're probably operating now at about 1/3 of the level of CapEx than what we saw at the first phase of the cycle. And as a result, we're coming in and seeing underinvestment by the E&P industry. But again, a lot of that reduction in capital investment is really as a result of reaction to prices. By the same token, the industry, I guess, recently, it got on one of these congressional panels, wanted to focus on how much the industry made last year, well, you really need to back up a little bit. And if you come in and if you really look at the last 7 years of the decade, these 24 constituents cumulatively lost $9 billion. So the industry has been through quite a cycle during this time period. And there's -- over -- I can't match Jim in length of career, but even over a 44-year career, I've only known 1 other time that we -- that the energy industry has gone through 2 troughs within about a 5-, 6-year period of time. And it always seems like that second trough is a little harder to overcome as far as coming back in and making capital investments and getting production to ramp back up. And then here, another thing that we pointed out here is while during this 10-year period, we've seen the NASDAQ almost appreciate 600%. We've seen the S&P 500 total return increased 350%. During this time period, crude oil production has almost doubled. The price of crude oil, and again, we're stopping this at the end of 2021, the price of crude oil since the beginning of the decade was down 25% and during this period, the S&P Energy sector, again, sort of lost paper with the investment community, and it's only up 11%, and most of that was in the last few months of 2021. So the industry really has faced some headwinds during that period of time. The other thing we try to point out to the legislators in D.C. that really want an instantaneous response from the E&P industry to ramp production immediately back up is the sector was really decimated over the 10 years and again, going through those 2 recessions that we're looking at 281 bankruptcies mainly in the E&P sector, but also in the midstream sector as well as 275 distribution cuts with the sector. I know you guys have lived it and seen it. But this is something, as we come in and we talk to people, especially in D.C. very many of them are shortsighted. So we need to come back in and give perspective of sort of what the industry has been through and why we just can't turn around on a dime and start ramping CapEx back up and ramping production up. That leads to the next slide where we come in and look at employment. And since the -- since 2014, we've seen the industry down about 44% from employment, especially being hit hard during the pandemic years. And I think that's one of the challenges that not only E&P, but especially oilfield service sector has really seen as far as attracting labor back to come in and man the drilling rigs and man the completion crews. And some of that, you get people back, but they may not have the same level of productivity and efficiency that those have stayed in the industry has. So again, somewhat of a challenge there.

I made a mistake, then that this slide deck Randy and I put together at the request of the legislator in Washington. So you're getting the benefits of what we sent out there. I think the point of this slide is hydrocarbons are globally traded. We import, but we also export and this country is blessed. We've become a net exporter of hydrocarbons. There was a time recently when I truly believe this administration was considering banning the export of crude oil. And a number of people got on a Zoom call with a legislator and talked about what would happen and we heard it last night, too. This isn't a barrel of crude oil. It's a barrel of energy. And there's a hell of a lot of associated gas goes with that crude oil and a hell of a lot of natural gas liquids that go with that crude oil. Crude production in the United States depended on exports, long before we lifted the crude oil export ban because we exported the heck out of LPG. And if we hadn't cleared the LPG, Tony, how much crude would have been produced? So this industry has always been dependent on exports, long before we lifted the crude oil export ban, and it will continue. And I think Tony is -- you're going to speak to it. This is a globally traded product, not just crude, but that barrel of energy. We're going to always import something, but we're going to be net exporters. I don't like the word energy independence. I like the words energy security because I think that's what's been achieved in this country. Thank God for George Mitchell.

Yes. So when we come in and again, we lead the deck off with as far as the U.S. oil and gas industry, we're still standing after a pretty tough decade. But also when you come in and you look prospectively, we're also part of the future. Things have shifted a bit here in the last few months where energy security has replaced energy transition as the highest priority. I think words like availability of energy, the reliability and stability of energy and also affordability, you're hearing that more and more. Daniel Jurgen, the Pulitzer Prize winning author and sort of historian of the energy industry. There was an article that he wrote in the Atlantic Magazine last November and where he really talked that energy transition is really energy addition. But if you go back in time, even back to the 1700s when we were transitioning from wood to coal will we never stop burning wood. When we transitioned earlier in the 1900s from coal to oil and gas, well, we never stopped burning coal, still burning today, still burning wood today. And then from his standpoint that when you come in and you look at some of the sources of renewable energy that will still come in, and it's just an addition to the energy mix, not a substitution or a replacement of oil and gas. And so we really believe that. We think the world when you come in and you look at the population growth, still growing about 1 billion people every 12 to 15 years. When it comes to energy, we're going to need all of the above to come in and make the needs of a growing population. IEA, depending on which forecast you pick when it seems like they move around these days. But even IEA when you came in and look at the demand for oil and gas going forward, that they were still expecting an 18% demand for production during that time period, granted more of the oil production may be going towards petrochemicals than what it has historically, but still we'll need these hydrocarbons going forward. The other thing, I think, that we've experienced in Texas last -- in February of 2021. But also, I think what the U.K. went through in the third quarter this year is more focus has been put on the intermittency of wind and solar and hydro and the need to back that up. And we certainly saw that in Texas in 2021, and I've got a slide on that here in a minute. We also think that we're on the early innings of a commodity super cycle. And especially when you come in and the expected demand growth, I think IEA had in May of 2021, had a pretty full analysis of the demand and future demand for the green metals and how much production growth that we were going to need of those green metals. And so when we come in there, again, the production is going to have to grow rapidly. And we come in and we [indiscernible] how much crude has increased in price over the last year, it's increased by about 60%. Well, when you come in and you look at the green metals, probably copper has fared the best as far as a lack of increase in price, but it's up 15%. Aluminum and zinc are up 50% -- aluminum -- or nickel is up 100%. Cobalt is up 64% and lithium is up 490% in the last 12 months. So inflation in this cost of metals and the cost of energy inherently is just not isolated to oil and gas, but you're seeing it throughout the energy commodities. Finally, when we come in and as far as the U.S. oil and gas industry being part of the future, I think one of the areas that we will see the first place where the industry can contribute is on carbon sequestration and our panel here later will really delve into that a little bit more. But when you think about the E&P producers, what better knowledge of the underground reservoirs do they have and then the midstream industry with the pipeline grid and be able to leverage off pipeline -- of the existing pipeline grid plus right-of-ways -- rights of way that we already have. So we think we'll be a first mover on carbon sequestration. And delving back in on the intermittency challenge, the Texas intermittency challenge. Texas has really been at the forefront of installing wind and solar energy. So when you come in and you think about Texas, it's the ninth largest economy in the world. When you think of it in terms of wind generation capacity, it has the fourth largest wind generation capacity at 33 gigawatts. Spain is fifth at 26 gigawatts. When you come in and you look in the United States, Texas has the largest installed base of wind, again, at 33 gigawatts. The second largest is Iowa at 11 gigawatts. So to a degree, Texas is a test study or a case study in how to manage through this intermittency. And we've tried to come in and show in those top 2 slides, what the volatility is or the intermittency is of the wind and the solar. And I don't think it's unexpected that overall, if you look at the averages, and we went back 2 years plus -- 2 years, but -- we went back from the beginning of 2020 through February of 2022 and for instance, wind over that time period averaged 40% utilization. And I don't think that surprises anyone. But the level of intermittency is pretty stark. So if we come back in and if we go back to February 2021 during the 3 or 4 days winter storm that Texas had, we actually saw wind production or wind utilization get down to 2.5%. So the swing of that going as low as 2.5% falls back on the natural gas peakers. And we actually saw that again this past winter in the cold snap that we had in February. We actually saw ERCOT has a pretty cool dashboard now where you can go out and look at what the day ahead -- you see what the installed base is, but you also come in and you see what the day ahead projection for electric demand is and also what the wind utilization would be, solar utilization would be. And during that last cold snap, we actually saw the wind get down to 1.5% utilization. Now you gave it a couple of hours, and it doubled. So it went to 3%. But still, the industry was having to swing back on the peakers. One of the other curious things that was eye opening is during that last cold snap, here in February 2022. The expectation going into that was Texas was going to hit an all-time record in power demand at 75 gigawatts. Now we wound up not getting there, but to think -- normally, we think of when Texas is going to have the greatest power demand is in those 95 degree days, 90% humidity days in August. But this wasn't -- this was in the middle of winter. And what was surprising to me is when you come in and look at the houses in Texas, 60% of the houses in Texas now heat with electricity that's not what you used to see. You used to see the homes heated with natural gas. So again, we put more and more load on the power grid. And so it just means we've got more stake from a reliability and a stability standpoint. So some of the things that we see, for instance, on our system and when you see that gas has to fill that gap when the wind doesn't blow and the sun doesn't shine, we've seen gas demand or swings on our system of 1 Bcf a day just in coming in and seeing the gas peakers come online as quickly as they can. Texas is coming in and learning from our lessons of February '21. We've got the Texas Electric Reliability Council Graham Bacon, our COO, is a member of that council, and it's really across the industry where it's power generators our midstream companies that are transmission companies. They are there together to help take the learnings from '21 and make Texas a more reliable system. One of the things that came back though from that is on some of these gas peakers, one of the things that are being evaluated is coming in and getting a more fixed ancillary revenue stream going to those power producers to come in and help support. They're having contracting for natural gas and storage firm pipeline capacity, and that's actually providing some opportunities for our natural gas pipeline group. But I think we're -- not only there we learning in Texas about this, but I think the U.K. went through this summer with when the wind didn't blow as much in the North Sea, and it didn't rain as much in Norway on the hydro. And with that.

I now One of the things I hope you get from this today is we talk about volatility. And Randy just talked about how gas is up and down. And that -- our job is to make money no matter what the environment is. So if things are volatile, our job is to embrace the volatility. And you've seen with all we've gone through this last decade, we keep performing, and it's our people that keep performing. During that freeze, we went the exact opposite way. I mean, it was just not in our DNA. Our DNA is run the plants. During the freeze, we shut the plants down because we could -- we've kept the storage running because we could sell the power and sell the gas and make more money than we could running the plants. It's just a way of seeing our people are so created. And my commitment is I don't care what the environment is. Our job is to make money. And that's who we are.

And probably the last thing, Jim sort of gave a teaser that I guess Brent's team is going to have a number of new projects that we'll discuss. You may need to write copious notes but also Chris Nelly will have a list of them at the end. So he'll provide you some context. So with that, it's good to be back in front of you live and in person. And I think you'll all have a good presentation for you today. Tony?

Okay. Well, I'm going to go ahead and get started. He's hooking up a speaker here, but I think you can hear me all right. So what are we going to cover today? Today, we're going to cover actually we always do macro supply and demand fundamentals, but we're going to talk about it globally. We're going to talk about price and what the history of price and what the projection of price is and maybe what might be wrong with that as we look at those curves today. We're going to look at our production forecast, and I'll talk to you about where our head is and why in and around that. And I guess, the last, but not least, we're going to talk again about petrochemical fundamentals. We've been talking the last several years as to how strong those are. And I didn't know they could get stronger. But from a long-term standpoint, as good as they've been in the United States for the last 10 or 12 years, I have to tell you they've gotten even better. So let's get started. Randy and Jim talked about the IEA. And we've climbed to wall of worry year-by-year with the shale and the oil and gas industry in the United States. We climbed that wall of worry all the way up to 13.1 million barrels. So the latest thing that everyone is concerned about is the demand will go away and you won't need oil and gas anymore. This slide tells you what the IEA said in their world energy outlook as to their stated policy scenario. So they show that growth will go up to 103 million barrels from 93 million, '21 to 2030. So that's plus 8 million barrels. In their announced pledge scenario, they show that number plus 1. And then, of course, in their net zero scenario, they show that number going down to, call it, 72 or 73. Next one. I've taken prices and I broke them down into 3 areas. I'll call them phases. Phase 1, Phase 2 and Phase 3. Phase 1, about a 5-year period from 2010 to 2015 and U.S. production increase from 5.5 million barrels a day to 8.5 million barrels a day. And we were in a really good price environment, let's call it, $80 to $100. And the reason for that is as the U.S. put more barrels on the market, the Saudis throttle theirs back to make way for the U.S. barrel and global markets. Then Jim and Randy alluded to it, then we come to December of 2014. And the Saudi stepped up in December 14 and said, we are no longer going to handle this market by ourselves. All the other players are going to have to get involved. So we had a sharp quick price drop and we hung out in that $45 to $50 range for an extended period of time, let's call it another 5 years. A lot of things happened during that 5 years, but I think the most important thing is the U.S. shale oil production grew from 8.5 million barrels a day to 13.1 million barrels a day in the first quarter of 2020. So that's 4.6 million barrels. Meanwhile, there's some time in there where the U.S. shale industry, bled red. I mean bled red. And the investor community got really tired of that. OPEC started a price war. Jim alluded to it, and then they looked and said, well, the shales have more staying power than we thought we can't take this, okay? So they abandoned their market share and went back established OPEC+ and found out that they're pretty adept at balancing the market. So that's what they have done. And so prices began to creep up. Now I'll call us in Phase 3. Phase 3 is where U.S. producers are signaling discipline, okay? And the markets are indicating that $75 to $85 is fair value for a barrel of WTI. The global surplus has been worked off. We're going to talk about that in a minute. And largely, the capacity the OPEC+ has held off the market has been worked off. We can see that in the fact that they have not been able to make their quotas. So that's the current environment. When I look at that $75 to $85, Jim talked about volatility. Well, this is -- we've been talking about this number here for the last couple of years, that 5-year range when you see all of that blue. And we've worked off that surplus and then when we project when we did our projections in January of this year and other people did theirs, it looked like the market was going to be stable, that OPEC was going to put barrels back on the market to the best of their ability, U.S. shale is going to grow. And most people were calling for plus or minus a couple of million barrels daily. Now we look at the April case and here's what we've assumed in this case. Now remember, the world likes about 3 billion barrels of crude and product. We've assumed that Russian volumes are down 2 million barrels a day, okay? I don't know. I can't tell you the answer to that. That's probably where they'll start out. They might start out 3, maybe a little bigger number. We assume that full [ IEA ] volumes are released of, call it, 240 million barrels by the end of the year and Iran stays off the line. One big question is can OPEC meet these obligations? I mean there's a lot of questions, but I would call this a worst-case scenario. The point I'm making is whether you're at this case that we started the year out before all this happened, or you're somewhere down here somewhere in between, you're a long way from being in your comfort zone. I look at that $75 to $85, and I understand that that's a mark on the curve. But at this point, I would say our bias without a doubt for oil prices -- and when I look at that $75 to $80 is biased to the upside. Let's go to the next one. Looking at gas and again, looking at 2 phases. Phase 1 is when shale oil production grew, grew substantially grew from 72 Bs to 94 Bs, so plus 22 Bs and the price of gas dropped like a rock, all right? That's Phase 1. The average price, if we look at that in that time period, 6-year time period was $3. I didn't go all the way back to 2009 because there are so many things that just gets confusing. When we go forward and look at what the price is when we put this slide together, we said $4.25. Facts are, at this point, that number I looked at it just before I came up here is $4.60. So is that fair value for U.S. gas? I'd have to tell you that it looks low, given all that's going on. I think there's a bid for U.S. natural gas from an LNG standpoint for an extended period of time, and I don't just mean for '23. Clearly, when we get out to '25 or '26, it would appear there's a bid for U.S. natural gas. So U.S. natural gas used to be tag along with oil, and it used to just be an associated product. But when you see that right there, it's come of age of itself. And let's go to the next slide. And here's why. When we look at the spread between U.S. gas and [ Asia ] LNG and U.K. LNG, look at that blowup that we've had, and we read about all these numbers and LNG, people that have LNG capacity have made a ton of money. But look at the forward market for it. So the forward market is telling you there is plenty of money to be made in LNG in the United States. If you look at what happened LNG spiked $60, even $70 at the beginning of the Ukraine incident. So we need more projects in the U.S. We'll talk about those in a minute. We also need permits and we need pipelines to be able to get the gas to these facilities because the world wants it and needs it. Let's go to the next one. So operational 12 to 13 Bs a day, I'm going to say under construction 9. Between this piece and this piece there could be some arguments. There could actually be arguments as to what's operational, but these are very large numbers. Very likely, even higher numbers and then potential additional. So when you add it all up, it looks like we're going to get to about 25 Bcf and it looks like another 10 Bcf is possible, but it's not possible without permits and pipelines. Is the resource in the United States to do it? Without a doubt, the resource is in the United States to do it. No doubt whatsoever. But we need to get permits and we need to be able to build pipes including out of Appalachia. So next, let's go to the next slide. All I want to hear all these plants and make no mistake about it. The people that own or control these plants are looking right here. And these people right here are looking right here. That's the name of the game. The name of the game as far as demand. We will have incremental industrial demand, but the name of the game is expanded in these plants along the U.S. Gulf Coast, there's just no doubt whatsoever. Go to the next one, please. Now I want to talk about our production forecast. We'll start with crude. So Jim called me out and said, how much is crude going to grow between now and the end of the year? I've taken the high road, and I've said you're going to have 1.5 million barrels a day of growth between year-end '21 and year-end '23. You can divide it evenly. The challenge is, I don't know the nature and can't tell the nature of the logistics bottlenecks relative to supply chains. You hear sand shortages. I think they're real. You hear pipe shortages. Certainly, labor trucking shortages. They're all there just like we're experiencing in our life, they're experiencing in the oil field. They will be resolved. So for now, focus on that number, 1.5 million barrels of growth, '21 average was 11.1 million not far-fetched to say we're going to 14.2 million in '27. What's likely to happen at this kind of environment and price scenarios, we're going to end up somewhere between these 2 cases. Give you some -- for those of you that like numbers, we're assuming in this base case that we had 5 rigs or think about 5 rigs as equal to 8 wells every month between now and call it the middle of 2023. In this high case, we're assuming though we add 5 rigs or call it 8 wells, so up to 200 rigs all the way through 2025. That's a very large number. Is the resource in the United States here to do it? The answer is yes. Is there -- are there any signals that the U.S. producer has an appetite to grow production that much and to and to deplete their inventory that quickly. And the answer to that is absolutely not. You're not seeing those signals whatsoever. Every day, okay? So we're very, very comfortable with this number. And I'll tell you at this point, and I think that number is low, somewhat low, given the trend that we're on, the momentum that we have. Let's go to the next one. And this is just the liquids number that goes with it, going from 6.2 million to 7.7 million barrels, high case, 8.8 million barrels. And for those of you that like the details, here's our breakdown. You see that it looks like about 47% of that is ethane. That's a big number. Let's go to the next one. Then here's the natural gas number, again, from $94. We're talking about $105 by 2027 for an annual average high case, it would be $111. I know that people are going to ask how do we think about what the breakout of where that is. Think about from a lean basis, think about 8 Bcf in the Permian, I think 3 or 4 in the Haynesville, a smaller amount in the Eagle Ford and other basins are actually going to decline. That's how we see that number. Again, that's lean. All right, let's go to the next one. So our rhetoric or our comments and our behavior relative to the Permian Basin has not changed. The Permian is a world-class basin. It's a basin that has changed the world. And it has a tremendous amount of runway, and it has a lot of staying power. I'll just say that it's amazing to me, but if we go back and look at the well productivity curves, that has increased by 8% every year since 2018. And remember, we had taken huge strides upwards from, call it, 2012 to 2018. So producers are still figuring out how to do more with less. Stacked pay over 13,000 horizontal wells have been have been completed during the last 3 years in 30 named geologic zones. Mostly the zones that you hear about are the Bone Springs, the Spraberry and the Wolfcamp, but there's a lot of the stack paying issues out there. We think there's about 9 million acres productive acres that we'll call Tier 1 through Tier 4. With $80 barrels, so we run our sensitivity, we think about 2 million acres moves from the lower tier to top-tier economics, which is Tier 1. Think about Tier 1 in the current environment, having payouts in something in months rather than years. So that's the Permian Basin, and that's the momentum in using Jim's words. That's what God gave us. Let's go to the next one. Brent, in his slides last year had the elephant in the room. You all remember in the elephant room is there's just way too much crude oil capacity. Well, I have to tell you, in the current environment, and this is the base case, this is the lower case. When we get out to 2027, that elephant in that room is vanishing pretty quickly. We would -- we would have never thought that last year. You look at the NGL numbers, I mean somebody is going to have to go to work. And you look at this natural gas number, we talk about this all the time natural gas basis is trading $0.85 back this summer, $1.75 next summer. So the 1 thing that we say on this slide, and I'll emphasize today, inadequate takeaway capacity can obstruct crude oil and NGL production capacity. When I look at these kind of balances, it tells me that Brent and his team, Natalie Gayden is going to have to get to work with processing plants. Zach Strait is going to have to get to work and his team with fractionators. Tug going to -- and he'll talk about it today, Tug has got some work to do with NGL takeaway. So the midstream industry relative to the Permian has some work to do without a doubt. The first thing they need to do is they need to build natural gas takeaway capacity. So people ask, well, is that going to throttle back production out of the Permian Basin because there's not gas takeaway capacity. I have to tell you, I think on days. I think there'll be days that it will. Permian, without additional takeaway capacity is going to have some bad days. What helps recovering more ethane helps because there is still ethane being rejected in the Permian Basin. Weather helps. If you have a cold winter, you have a hot summer, that helps. If none of that happens, you have more issues in the Permian. I think at these kind of oil numbers where the market is going to have to go to work and figure out how you produce oil and get rid of natural gas, okay? And Brent always asked me the question is -- does that mean that gas in the Permian Basin is going to be competitive with other basins? And I answer it this way, there is no comparison between economics for gas in the Permian compared to any other gas basin because there's so much profitability in the oil. That natural gas can be sold at a significant discount even given a way at a significant discount. I'm not saying that's going to happen. But the economics of getting natural gas out of the Permian are going to be like something we've never seen before. Okay. Let's go to the next one. I love this graph, and this really is the heart of our petrochemical efforts. If you look again, pre shale and post shale, you look at the -- on the left and we look at the gas to crude ratio. So prior to the shale blowout and call it, 2009, 2010, that number set between 60% and 80%, okay? And we kept looking at the amount of natural gas and liquids and Enterprise and other people -- we're telling the petrochemicals, you need to get to work. Jim was telling them, everybody would say, "Well, Jim, how do I capitalize on this and he tell them all you needed to be the first 1 to build petrochemicals in the United States. So we look at all these petrochemical additions we have and look at that number. So that number is still sitting around 20% to 30%. That's why we've made $200 billion or more of petrochemical investments, and I have to tell you, when I look at that curve, there's more to come. Okay. Let's go to the next one. One -- there's a lot of lines on this page, but if we look at C2 as a percent of WTI in the 2010 to call it, 2012 time frame, 33%. Now it's at about half of that at 17%. So the barrel that makes the most money today, and actually, there's a lot of days it's the barrel that's making the only money is the U.S. ethane barrel. Now that doesn't mean that other plants can't run that they don't have derivative upside. But when you look at this and you look at how steady that line is, I don't think we're done with ethane and ethylene in the United States. And then let's go to the next 1. So I think Chris is going to talk about a number we've been talking about for a long time, and that is that we -- ethylene and propylene primary petrochemical demand is 1.3% to 1.4% of what global GDP is. Looked at back at 2020 just as a case study. So 2020 world GDP declined by 3.5%, oil declined by, let's call it, 9%. Ethylene and propylene demand held as steady as it can possibly be. That is the backdrop for these primary petrochemicals that the world enjoys and particularly the U.S. shale producer and our industry here. Let's go to the next one. It's an interesting slide, and I know there's a lot of data on it, but I'll cut to the chase. If you look between '25 and 2012, we had 1% compound annual growth rate in LPG demand in the world, okay? If you look at what happened after the U.S. shales came on, we did 4x of that. So 280,000 barrels a day of growth every year, and that's because the U.S. shales had it. When we do our balances going forward, assuming that the U.S. is the only 1 that has LPG and largely, I believe that to be true. We're looking at demand of 250,000 barrels, okay? If we look at what the supply is annually out of the U.S., we're talking about 100,000 to 125,000. So the question is, how do you balance global LPG markets? And the answer, the easy answer is you either produce more out of the U.S. or something does not get the LPG that it wants. That's the situation. Those are the balances. It's not hard math. This is the reality. This is the underpinning for U.S. LPG into global markets. These are very, very positive economics, of course. There is a continual bid in some form or fashion for the U.S. LPG barrels. Sometimes it's being bid to stay here. sometimes global markets are bidding it away. Let's go to the next one. I think this is my last slide on fundamentals. Look, we started out importing 10 million barrels of liquid hydrocarbons when we started the shale revolution. And look at the steady decline in that to where we went to a surplus. So if you take our numbers, depend on which case and you take some demand instruction in the United States and you look at where we're headed, there is a significant amount of hydrocarbons that U.S. is going to put on global markets and global markets need it. What that tells you is Enterprise's position on the Gulf Coast as good as it's always been, is getting ready to get significant amount better. I think that's my last slide. And it -- thank you very much. Thank you.

All right. Good morning. I think every Analyst Day, we start off with the Enterprise map. And this map is grown and changed throughout the year with the addition of assets and developments. And this is a map that we're extremely proud of. If you were to go back when Enterprise IPO-ed, there was less than 200 miles of pipe on that map. And to where we are today, I think it's something that everybody whoever worked at Enterprise is extremely proud of. During this presentation, we're going to take a look at how these assets were developed because I think it's important because it's going to give you some insight on how these opportunities that we see ahead of us are also going to be developed. Before we talk about that, I want to tell you what this map represents. It's a system. And it's a system that connects producers to consumers. It's a system that has direct or indirect access to every producing basin. It's directly tied to every pet chem facility in this country. It has access to every Gulf Coast refinery and ultimately, it's tied in the largest storage complex in the entire world. It's a true system, it's incredibly difficult to replicate, both in cost and the constructability of it. How we view this as a system of options, and it's positioned us to capture the market dislocations as they appear and also capture the growth opportunities that we see coming ahead that Tony mentioned. In the words of Dan Duncan, the more barrels you touch, the more opportunity to make money, and I don't think true words have ever been spoken. As we go further into the commercial details of this presentation, you're going to hear a recurring theme about how we are positioned for growth, both with our existing assets, you saw on the previous map and then also with the opportunities that we've identified and ultimately, when you put those 2 together, it is going to increase the entire use of the Enterprise system. Enterprise takes people to markets, and it's symbiotic in nature in the sense that it brings buyers and sellers together. That's going to also help us when it comes down to throughput. And that's the mindset that we're going to have as we go forward. And it's going to be a mindset of a long-term ownership. I think Randy and Jim in the past have talked about EPD unitholders is short-term owners and long-term owners. How we think about things as we go about trying to find deals, it's one of a long-term mentality. We often ask questions about our capital expenditures. And today, we're going to give you more clarity on exactly how that money is going to be spent. We have 7 new projects to announce today, and you're going to hear the words over and over capital-efficient. And we use the words capital-efficient to us is much of the work has already taken place on that big map. And the capital-efficient projects that we do are going to be bolt-ons to enhance the entire value chain for Enterprise. And the integrated economics that we have with that map is what is going to provide very attractive returns for all these projects for us. And 1 final note, the capital that we're going to deploy is going to stay within the capital guidance that we have previously provided. The graph at the bottom of this page contrasts the flat price of crude oil with Enterprise's financial results the last 3 years. And the word contrast was chosen specifically because it's does just that. It's a contrast between reliable and volatile. Commodities and markets are volatile in nature, but the Enterprise results were extremely resilient. We're very proud of that. And you might ask how this was achieved. I think 4 or 5 years ago, I was on this stage, and I talked, if you just boil everything down about profitability for Enterprise, it was essentially 3 key strategies. It was location, it was time and it was product upgrade. And each year was something different over the last 3 years. Those strategies coupled with our term contracts, that integrated asset footprint you saw earlier and then the Enterprise culture that Jim had mentioned, and it's a culture that always embraces a good challenge. That's what allowed us to achieve those results. That graph at the bottom, it's going to change over the next several years, and it's not going to be a story about resilience. It's going to be a story about growth. The opportunities that we see ahead with domestic supply, the past investments we have made, coupled with the opportunities that we see coming is going to enhance the entire value chain of the system. I showed this slide last year, and it was merely an acknowledgment. I think Tony just referenced, it was an acknowledgment that the midstream space was overbuilt and there was too much capacity. And it wasn't specific to any particular service. It wasn't specific to a commodity or location, it was just this thing is overbuilt and supply needs to catch up. Over the last several years, any kind of midstream capacity addition, it's been dormant, and it made a lot of sense as the pandemic caused the supply curve to get pushed forward. It's important to note, and Tony talked about this, the theoretical nameplate capacity. I know everybody in here has their analysis of capacities. I don't care, if it's a pipeline or any other kind of midstream service. I'm going to tell you it's probably overstated. This industry is going to face supply chain issues, and there will be connectivity constraints. And there are also increasing costs. And as production approaches this theoretical nameplate capacity, these systems are going to get stressed. This is going to add to the volatility in the market. The capital that we have invested over the last several years is going to position us with an opportunity to realize the growth that Tony spoke of. And we will continue to embrace the volatility and capture the market dislocations as they appear. We have always done that. And we're going to -- we will continue to have a long-term owner mentality in terms of how we approach this business, both of the benefit of our customers and also to the unitholders. Before I introduce this panel, I want to reiterate the 3 key points. The 7 announcements that you're about to hear coupled with the past investments that we have made is going to allow Enterprise to participate in the supply push that we see coming ahead. Number two, I think Jim already said this. The value of pipe in the ground continues to go up. It's much harder to construct. It's also a lot more expensive. And number three, the Enterprise system has unrivaled connectivity and integration, and it is incredibly difficult to replicate. Okay. Joining me for this discussion is Natalie Gayden, our Senior Vice President of Natural Gas; Tug Hanley, our Senior Vice President of Pipelines & Terminals; Chris D’Anna, who's SVP of Petrochemicals and Justin Kleiderer, -- he's the Senior Vice President of Marketing, and you guys pay attention because I think Natalie, I think you have 3 of the announcements, right?

Yes. My announcement is probably aren't as cool as Tug. So wait for him. Over the next several slides, I'm going to talk to you about our gas processing business, which really is a great business. It fits well into our vertically integrated value chain. And we are the first touch of the molecule, and Brent's already told you, touches a molecule equates to opportunity. It's a great story. If you think about it in 1998 before we went public, does anybody know how many gas processing plants we owned? And how much Y-grade we produce. Zero, the answer is 0. After several acquisitions and many new builds, this business really grew. And today, you're just going to hear that growth story continue, but it's really 1 of successful strategic and disciplined execution. Two months ago, we acquired the Navitas asset. We've been looking at this asset for a long time. Our -- after this asset, our processing portfolio expanded to 23 natural gas processing facilities. Most of those facilities have more than 1 cryo or more than 1 train in them. And of course, we span multiple basins. So from processing 0 in 1998 to now processing over 6.5 Bcf a day and producing over 650,000 barrels a day of Y-grade, I'd say, part of the growth story has already happened. Why did we target Navitas? Well, I told you we're looking at it for a long time, but here are several reasons why. We wanted to be in the Midland Basin. We believe in the resource, and that's just a core strategy with this company. The rock is great. Tony has told you about the stack pay zones and the light sweet crude oil that it produces. We like the producer mix. So during a time when majors aren't really talking about growth, independent private producers, I'd guarantee you are growing. And this asset had an exposure to those Midland centric private producers. We wanted more exposure to commodities. So the commodity price outlook, coupled with the types of contracts that this asset is backed by, which is our significantly commodity-based. But 1 thing we like about it is there's a minimum margin component to it. These types of contracts put us in total alignment with our producers as well. And then last but not least, Enterprise has always believed in the quality of construction and operation. I think Graham's team in the due diligence room and visiting the assets was absolutely impressed. This is not the private equity typical build where the pipe is held in the ground by the dirt grounded. This was a true asset and we noticed it. There are downstream synergies. So we are connected to our NGL pipe for Y-grade and our residue pipe. So as downstream contracts roll off from this asset, we will certainly evaluate any that we will take advantage of and for the best for Enterprise and our customers. So I told you the growth story continue, and I'm going to announced the first announcement today. We are building already in motion a plant 6 in the Midland Basin. It's a 300 million a day cryo. It will sit in the same type or very similar complex that most of the assets sit today are the processing plants. We anticipate it will come online first quarter of next year. And after the plant is up and running, we will be processing 1.3 Bcf a day. The plant will be full. So there's a real simple answer on why, just to tell you a little bit more about this asset. We have over 450,000 acres dedicated to us long-term for processing and production. Forecast from that acreage indicate that we need capacity. So the plant will be full. The production forecast that you see on this chart to the left, it doesn't account for any onload opportunities. and it doesn't count for any optimization that we may have, nor does it account for business that I'm sure you are chasing every single day. All right. Moving on to the next door neighbor of Midland. We have our Delaware Basin gas gathering and processing business. And honestly, less than 10 years ago, we were processing 40 million a day in the Delaware business. And so I went in doubt if there was a recommendation to divest the time or 2 from commercial, but good thing we didn't. So if you're taking notes or if you're tweeting them, the second announcement today is we are finally building Mentone II. So 300 million a day cryo, it's going to sit next to Mentone -- our first Mentone plant in that same complex, absolutely capital efficient because our gas gathering is already designed to feed the plant. So there's no gathering infrastructure that we'll have to build. That will bring our total Delaware processing capacity to 1.9 Bcf a day and producing over 270,000 barrels a day of Y-grade. I'll go ahead and do the math for you. With the Navitas asset and the expansion of Plant 6, we will be processing 3.2 Bcf a day in the Permian, producing over 450,000 barrels a day from our gas plants. In the Delaware, most of our plants have really been built in the last 5 years. So if you think about it, South Eddy and Delaware Basin gas plant were built in 2016, but 3 Orla trains, all 300 million a day cryos were built in '18, '19. And then our first Mentone plant was brought on not soon long after that. But we have been disciplined and we're going to remain that way. However, it's really time to build Mentone II. Our gathering footprint in this basin started out as a small lean gas system, but it positioned us to grow to the super system that it is today. All right. And if you follow midstream bottlenecks, then it's really no shock, if the Permian is short, natural gas takeaway capacity. And we can argue about when the short will happen and how short it will be, but the answer is still the same. The basin is short takeaway capacity. And if you're watching the market, it shows all the signs of the takeaway constraint to. So on January 1, if October 2023 is a point of reference, on January 1, it was minus $0.85. On February 1, it was minus $1.50. On March 1, it was minus $2.50. And maybe the market has gotten a little bit more confident about it in the last week, but the answer is still the same, it's indicating a short. So a point to make there. We have 300 million a day of available uncontracted capacity in 2022, 2023 on our Texas Interstate pipeline. And we are certainly having healthy conversations on the best use of this capacity for Enterprise. And that's just a core strategy that we exercise every day here. Okay. You have to talk about the Haynesville. It was really one of the first basins to return to pre-COVID rig activity, great rock, great producers behind the rock. But just a little history lesson on this map that you see, and it's really one of just Enterprise building markets. And we bought that legacy system from Shell not long after we acquired the Louisiana processing plant through the [ Tejas ] acquisition. And that's, I think, when we got our best acquisition yet, Jim. It's thousand miles of pipe in an industrial demand center. And then in 2008, the Haynesville took off. So in 2009, there were a lot of interest from producers to get prolific Haynesville production to this growing industrial demand center. And so we said we're going to build a pipe back by 100% take-or-pay contracts and link the Haynesville to the river corridor. It's 250 miles, and it came online in 2011. And at that time, it was capable of moving 1.8 Bcf a day. Last year, if you remember, we expanded that system and we were capable of moving 2.1 Bcf a day. That's also when we built Gillis. Remember Gillis is the pipe that comes off of the extension and goes to LNG export hub. It is a Bcf a day. So the third announcement that I'm making today is we're expanding the Haynesville extension 1 more time by 400 million a day. It's capital-efficient, Brent because it's compression only. Certainly, backed by 10-year 100% demand contracts. After -- when it's complete, which we expect 3Q of next year, we will move 2.5 Bcf a day of Haynesville production to LNG. And everyone talks about LNG. So on the Louisiana side, by 2026, LNG is going to grow by over 4 Bcf a day. But that little river corridor is also growing. So when you think of methanol expansions, you've heard a blue hydrogen plant being built in Louisiana. But the 1 closest to our heart is petrochemical expansions along the Gulf Coast, all of these require more natural gas demand. And Chris is going to get to that in a bit, so stay tuned. Our gas gathering, processing and transport business is really just the start of a phenomenal value chain of energy, but it's certainly not the end.

All right. Thank you. Here we go. You heard Brent talk about the durability of our gross operating margin during times of volatility. And that durability really comes from how we view assets, which are as options. If you look at the graph on the right, you can see that we're expecting NGL capacity to start to get tight late 2024 and early 2025. And I will tell you that graph might be conservative, which we'll address a little bit later. Presently, our Permian NGL pipeline capacity stands right at 1 million barrels per day. It's connected to multiple basins Midland, Delaware and our other Maple Rocky system basins up there in addition to the DJ. It is fed from multiple third-party gas plants and producers who value the flow assurance, and market choices that we can offer. And coupled with Natalie's existing equity production, which is increasing and announcements that you just heard her make, our utilization has gone up, and we expect it to continue to do so. Let's just look at Shin Oak as an example. Shin Oak's utilization in the first quarter of this year was just shy of 500,000 barrels a day. If you look at the first quarter of last year, that's over a 40% increase in utilization. I think that really -- if you look at the quote that Brent mentioned earlier, Dan Duncan about touching as many barrels as you can, I think that really emphasizes that. So last year, I said I don't know if these pipelines are in the right product service or if they are flowing in the right direction, but I do know this. We have a very successful history of repurposing assets. ATEX, TE Products, Seaway, Seminole and there are others on that list. They can continue to go on. So we're often asked questions about the decline of NGLs in our MAPL Rocky system, [indiscernible] we're going to address that over the next few slides. Before we do that, though, let's talk about TE Products and let's talk about the history of that asset. TE products is comprised of 2 pipelines, originally want to transport refined products from the Gulf Coast to Chicago and markets along the way, and another to transport LPGs from the Gulf Coast to the Northeast. Think propane to New York. And then there were 2 fundamental changes in the market resulting in TE no longer being the preferred mode of transportation. First, Mid-Con refiners became more competitive as they embrace the Canadian crude growth story. Second, we got it from the other side, the Marcellus Utica production started to take off, and propane was now produced locally in the Northeast, no longer needed a source in the Gulf Coast. Needless to say, in 2013, the throughput on TE was dismal. We had 2 pipelines that were less than half full. So we had to embrace the change in the market. We got involved in the Marcellus shale story and we repurposed the line, provide ethane takeaway to the Gulf Coast. That is what is ATEX today. We consolidated all northbound movements to a single pipeline and establish diluent service. If you look at it, both the Marcellus NGL story and the Canadian growth were competitive threats turning to market opportunities. ATEX today is now fully contracted with long-term take-or-pay contracts and TE's utilization is oftentimes in excess of 90% and at times on allocation as well. Now a mixed TE so successful is the diversity of product service that I can offer. We can transport over 10 products on TE. And the markets are interesting. You'll see a decline in motor gasoline demand and then you'll see it more than offset on an increase in distillate demand or NGLs or diluent. So it's a very diverse mix of products late that it can move. Out of all the products we can transport on TE, we let the market tell us which 1 it values the most. In addition to the market that TE serves, the demand is very durable. Once Iraq is established to our pipeline, it is cost advantage and competitive. Our pipeline is the most cost-efficient means to transport volume at scale far more efficient than trucking from long distances, rail or barge. Once the demand is there, is there to stay. And this year, we are looking forward to adding another addition to our products late on TE. We're going to be adding to natura -- natural gasoline as a service to Mid-Con ethanol plants. All right. Next slide. All right. So we just finished talking about the product diversity TE can offer. So let's write this down, get your pencils out. Our fourth announcement is we're going to be adding refined product service to our Western region assets, notably our Maple Rocky system. This system will run very similar to how we operate TE today. Simply put, product diversity increases utilization and increase in utilization increases profitability. Our MAPL Rocky system from Hobbs that Utah is underutilized. As we all know, those basins have been in decline. But if you really look at our MAPL Rocky system, it's not the single pipeline, it is multiple parallel pipelines in the same right of way. We're going to consolidate all NGLs to the legacy pipeline system and establish refined products flow north to Utah from Hobbs. And then we're going to take Chaparral and we're going to integrate that into our Southern Complex system, which has access to one of the best supply sources of refined products in this country. This is very similar to our TE products as supply today. Product service will be established on Chaparral from the Gulf Coast back to Hobbs, 4 new product terminals we've built, 1 in Utah, located near Grand Junction, serving the Grand Injunction market along with other Eastern Utah markets. Another in Albuquerque, serving the metropolitan and surrounding area. Hobbs, Texas, serving Odessa, Midland and other West Texas markets; and then a single product terminal in Jal, New Mexico to provide the producers in the Delaware diesel. Diesel is a key component to drilling operations. We get asked that question every day when we talk to our producer customers. The integration and value chain the Enterprise has is what makes this product possible. There will not be any new build pipeline required for this project. We are simply repurposing existing assets, which leads to a significant cost reduction. In the graph on the bottom left, if you look -- you can see the premiums and Grand Junction are substantial versus the Gulf Coast. To go over -- if I look here today, as I tell you this today, we look at the prices this morning, diesel is just shy of $0.80 per gallon over the Gulf Coast. And if you look at Albuquerque, New Mexico, while not as impressive as $0.80 per gallon, it's hovering around $0.45 a gallon right now. So once in service, we're going to have enhanced the value of our MAPL Rocky system, Chaparral and our Southern Complex system. And the market's going to welcome these new supply choices, because it's a cost advantage. It's reliable and abundant, but most importantly, the market's choices are limited day. They are captive to local production. The other positive knock-on effect of this project is all of our pipelines are going to see an increase in value. Total utilization will go up. If you recall earlier, that graph on Permian NGL takeaway, how I said I thought it was conservative. This project is why I think it was conservative. First flows are expected in the second half of 2023, and I will tell you, I'm really excited about this project. It's going to provide a much needed relief to the high gasoline prices of the pump in West Texas and the Rockies corridor that MAPL traverses through.

All right. That's a neat project. I remember during COVID when we had a lot less meetings, there was less people in the office. That's how that project got identified as I remember Tug and his team having the map of all the pipeline assets, and they had our values of differing commodities all over the map, and they identified what the value of diesel and gasoline was in Grand Junction, Colorado. So credit to Tug and his team on identifying that opportunity. All right. As we go downstream with Y-grade, I want to spend some time to talk about fractionation. I think Tony had referenced some of this earlier, if you were to go back, and this is another history, listen, if you go back to 2001, when Enterprise bought MAPL. Enterprise did not own or operate its single Y-grade pipeline. We were totally dependent upon third parties to provide us with supply with what we had such a big investment in. When you look at the fractionation portfolio today, it's the integration of our fracs with our pipeline assets is what makes it a true system. Beyond 18 fractionators from South Texas and Louisiana, we got 1 out in West Texas, which is an incredibly valuable fractionator as well. And we can essentially move Y-grade to wherever we want it and we can get those purities back. If you were to go back to 2019, it's a period of time in Enterprise, we call frac media. And as you recall, I think frac fees got right around $0.50 a gallon. We leaned heavily on that non Belvieu fractionation. And we lean heavily on our storage position to go stockpile Y-grade until we saw a brighter day when we get it fracked out. But it was our ability to provide that flow assurance and it was the connectivity that allowed us to meet our customer needs. And that reliability, frankly, is why I think that sets Enterprise apart. So while our capacity is flexible, go back to Tony's forecast, we have to be ready to handle the sustained long-term growth that we see ahead. So as expected. It is clear that more fractionation capacity is needed in this industry. And that's why we are pleased to announce our 12th fractionator in the Mont Belvieu area. That's our fifth announcement. And it's another capital-efficient project, and it's capital efficient for quite a few reasons. First of all, the base infrastructure in Mont Belvieu, that's already in place. And secondly, most fractionators are built with 4 towers. This only needs 3. We have enough DIB capacity to handle what we need. And then the last piece is this was a project that we actually sanctioned prior to the pandemic and it got delayed. So the majority of this equipment has already been ordered. And as a supply push as the supply was pushed out, we held back on it. This project is supported by growth from our third-party customers along with what Natalie discussed earlier with our G&P customers. And while it's under construction, we're going to lean heavily on the non-Belvieu fractionation. And candidly, we're having to use it already. That's where the volumes have gotten to. Once online, frac 12 is going to be another cognitive wheel of the Enterprise value chain. It's going to support our upstream production from Natalie and it's going to deliver value to our downstream with what Chris and Justin have. Talk a little bit about LPG exports. What most people don't realize is we started in the LPG export business way for the shale gas revolution. We had a JV with [indiscernible] that was importing Algerian LPGs and often reexporting those LPGs to Latin America. That was happening as the early 2000s, way before the shale gas revolution. This incumbent asset base and this incumbent experience allowed us to capitalize on the changing market dynamics around the shale gas revolution and put us in a position to be a first mover to become what we are today. And that is still one of the largest LPG exporters in the world. When you look at the chart on the left, you'll see a familiar contract roll off schedule and that is our contracts are short-term in nature. And every year, every quarter, we get asked, how do we feel about LPG export contract roll-offs. But at the end of the day, we're really comfortable with short-term contracts in this business for 2 reasons. One, what most of you don't probably realize is half the volume that's exported across our terminal is from customers that have been with us since day 1 of our original expansions. So all those contracts are, for the most part, rolled off and now are year-to-year. But we specifically targeted sticky demand via downstream distributions. And we and they intentionally come back to us every year because they know that we're a reliable supplier. So that's half of the volume that looks like is rolling off that we know is going to be there. Second, if you were to take this chart and overlay it with the chart on the right, you'll see a story that's very compelling as we go forward in terms of how we feel about LPG export contract values. The wedge on the right-hand chart, between 2024 and '25 starts to grow relative to how much capacity is available to handle the incremental supply coming out of the Permian. And so as we go into that time period, it's beneficial to us to have the ability to determine how we want to go about contracting. So that's a significant value. Now most of you are probably asking with this wedge widening between supply and demand, where we are we on expansions. We're not announcing 1 today. It's not a part of the list of 7. We figured 8, maybe too many for today. But we still have our expansion that we announced prior to COVID. That's still on the shelf as well as a number of smaller more quicker expansions that will bring off the shelf if the market determines we need it. And we'll do just that. We'll react to what the market needs. I think Bob will allude to one of those more shorter-term lower capital options in his notes. Moving on to the ethane front. Brent were to ask me what are we most constructive on, on an export basis. My argument would be that of ethane. Tony touched on all the fundamental drivers behind what's driving the cost advantage nature of ethane relative to other feedstocks in the U.S. and globally. It's also fitting into every LNG substitution pool that's able to take it. I think every single one of our ethane export customers today is fueling ethane in lieu of LNG that makes way too much money. And so all we need is a little bit of time for these markets to develop because we don't think this cost advantage is going away. And so the momentum is starting to build there. We're starting to see brownfield projects starting to get looked at again at all over the world, various debottlenecks from existing assets. And we're starting to field the phone calls again about multibillion-dollar greenfield projects in various different places around the world. That momentum is starting to bear fruit. Our sixth announcement today is the fact that we have long-term contracts to support a second ethane terminal along the U.S. Gulf Coast. This ethane terminal will -- will be somewhere along our ethane header system between Corpus and New Orleans. We're still working on final site location. We'll provide details when we make that determination. This terminal is backed by a long-term agreement with our long-standing ethane export customer, INEOS. When INEOS approached us with this opportunity, they were adamant that a second terminal was needed to be able to step up their commitments. And the reason for that is because ethane is more milk run, more point to point, it's not a truly waterborne trade, commodity is not fungible. And so as they're developing markets around the world and supporting our value chain via their waterborne logistics, it was important to them to be able to show that they have supply reliability and supply diversity because it's important for these multibillion-dollar investments that are being looked at across the world. We're okay with it because it creates significant flexibility for us at Morgan's Point. If you can refrigerate ethane, you can refrigerate just about any hydrocarbon that we deal in. And so that creates some significant flexibility and optionality relative to what we want to do with our existing capacity at Morgan's Point. So I won't steal Chris' thunder, but I think he'd take me up on the bet about which 1 were more bullish ethylene versus ethane, but it frees up some significant flexibility on ethylene that he will speak to her later on.

All right. Justin just showed you the abundance of ethane and how it's a global feedstock. Well, it's premier domestic feedstock as well. The supply push of volumes from the Permian you've heard everyone talk about, that's translating directly into opportunity for us downstream. Between our South Texas and Aegis system, we have an ethane header all the way from Corpus Christi in Mississippi. Aegis has over 425,000 barrels a day of long-term take-or-pay contracts, and we have the ability to add an additional 50,000 miles a day of supply to the connect petrochemical facilities, but little to no capital. When we meet with our customers along this pipeline system, the first topic that comes up is their plans and evaluations for future expansion opportunities. And like most of our assets, the hard work is already done. We can expand Aegis by another 200,000 barrels a day with a cost-efficient expansion and we're going to be ready for our customers as they make their evaluations on their debottlenecking and expansion opportunities. You just care to talk about how all of our customers on Aegis want more ethane to make more ethylene. And a little bit earlier, you heard from Tony about the global fundamentals around the petrochemical industry and how durable it is. I'm going to spend a little time talking about why we believe in the U.S. ethylene and propylene growth story and how we're positioned to take advantage of that. The chart at the top of this slide shows that ethylene and propylene continue to grow at rates well above GDP. And Tony touched on this a little bit. But the reason for this is because ethylene and propylene go into the products that are growing global population needs. There are things that you and I may take for granted, but they make our labs better every day. It's things like carpet, flooring, refrigerators, mattresses, furniture, lightweight cars and many, many more things. And that's why the demand story is still very much intact. So if ethylene and propylene are needed and they're growing where are they going to be produced? Well, the U.S. has held a sustained feedstock advantage, thanks to our U.S. shale producer and the ethane that comes from it. In fact, this is really the reason why over $200 billion in investment has happened in the U.S. for the petrochemical industry over the last 10 years. But there's another factor that's not talked about nearly as much. And that is that the U.S. has stable, low-cost energy, think electricity and natural gas. In fact, I can make an argument that a cracker built in the U.S. could save $600 million a year just in energy costs. So you combine that along with the $1 billion that Tony talked about with the feedstock advantage and you could pay for a new cracker in less than 2 years. That's why we believe that the U.S. will continue to gain share of the global growth. And that benefits not just the petchem business with Enterprise, but all of our businesses. Next, I'm going to talk about how we positioned some of our businesses to take advantage of that growth. Moving a little bit downstream. The picture at the top of this slide is our ethylene system. If I would have shown this slide 5 years ago, it would have been a blank page because we didn't have an ethylene business back then. But back when the first shale crackers -- after the shale revolution started and crackers were starting to get built in the U.S., we developed a strategy on how we could participate in that growth. We designed a header that connects producers and consumers to an open access hub to an export terminal to connect us to the global market. That's really our standard playbook for all the commodities that we participate in at Enterprise. But it's really pretty revolutionary for ethylene, where historically, a few small producers would have pipelines that they would use to deliver product to the customers. And oftentimes, when a customer needed to get a transportation deal, they were relying on a competitor to move it for them. That's why every connection that we add to our header is significant, both in terms of what it does for the industry as well as what it does to our overall throughput. So as the U.S. industry continues to expand, our system is going to become more important. Long-term, our goal is to create an Aegis like header that spans the Gulf Coast. The heavy lifting for this has already been done. We already have a pretty significant pipeline system. And that pipeline system was built with contracts that have 20-year terms with take-or-pays that back the volume on that. So longer-term, we believe in the growth story. We believe that as ethylene grows, our system is going to see that throughput and be benefited from that. Next, I'm going to talk about our propylene system. Our propylene system is very similar to our ethylene system, except it has grown over 40 years instead of just the last few. We started off with a single JV pipeline splitter with a pipeline and splitter JV, and that's grown to 7 splitters today. We're starting up our second PDH next year about this time. And when it starts up, we're going to have 11 billion pounds of production. We're going to be the largest producer of propylene in the world. Even though it's a mature system, we continue to grow. Remember what I talked about with the fundamentals where ethylene and propylene are both growing greater than GDP. Well, propylene in the U.S. is growing quite a bit. We're going to have over 2.5 billion pounds of consumption that comes online next year and our system is going to benefit from that growth. You can see how our throughput started off in 2019, relatively high, but it's continuing to grow at a pretty good clip. So as new production and consumption comes on the line in the U.S., our system is going to benefit from that. Moving further downstream, I'm going to talk about our export terminals. Our export terminals is what connects our systems to the global markets. Our propylene export terminal has been in place for many years. It's the largest of its kind, and it has sufficient capacity to meet the world's needs when the market says there's a need. Both our ethylene and propylene terminals have the capacity and the ability to co-load with NGLs, meaning that our customers can load ethane and ethylene together, propane and propylene together. It means they can get bigger ships and they can access lower freight rates for that. Our ethylene terminal started up in 2019 as we finished that project, and it's been ramping up ever since. Over the last 6 months, we've hit new records. Today, we're operating over 125% of nameplate. It's not enough. The terminal is full. As the rest of the world is struggling with high energy and feedstock prices, they want more across the dock. Both our U.S. ethylene producers want more. Our international customers want more. So I'm happy to tell you that our seventh announcement today is that we're going to be expanding our ethylene export facility. Justin mentioned the ethane dock that we're going to build and how that adds flexibility and add some opportunity for ethylene. It absolutely does. It's going to make our expansion very cost efficient because we have an existing footprint there that we can use. We have some existing equipment we can use. That expansion is going to be online at the -- in the second half of next year. It's initially going to be a 50% capacity addition. Eventually, it will be double what we have today. So Justin talked about, we can argue what we like more, whether it's ethane exports or ethylene exports. I like both. And I think the market is going to support both very well.

All right. So we've hit all 7 projects, but we still got to run through the gathering system, so bear -- or the crude system, so bear with us. I'm going to take the gathering system in the Midland terminal. So let's go all the way back to the basin for a minute. As you -- as we think about our gathering system, we'd like to sum it up in 2 points. First is the projects associated to the gathering system to bring additional tank batteries and additional well connects are small capital, small dollars in nature. But they offer some of the highest risk-adjusted returns across our entire portfolio. So though on a stand-alone basis, they're not needle movers. Across the gathering system, they do add up to pretty compelling numbers. Second is success in this business breeds opportunity. So the gathering system is all about coordination, communication on the timing of production behind your dedicated acres in the -- behind the gathering system. And your ability to be on time and be on budget relative to what producers need you to be, oftentimes leads them to want to do more business with you, above and beyond just the gathering system. I can't tell you the number of times that 1 success on 1 tank battery connection has evolved into a large gathering and processing deal down the road. It's the building block of our -- the base building block of our relationships with a lot of our producers. All of our gathering system volumes flow into the Midland terminal. And this is the first time I hear us talk about it, but we're going to talk about it here again shortly is the Midland terminal is really the hub. It's the clearing mechanism for the basin. It's the pricing point for the basin, and therefore, everyone wants access to it. Our gathering system closed barrels into it and as production grows, all the other gathering systems will continue to want access to it as will all the long-haul takeaway pipelines. Because at the end of the day, there's only 1 way to balance and need a hub to do it. And so as the terminal -- as production grows, and the terminal evolves to see throughputs grow, our gathering system always knows that once you hit the terminal, you always have a bid to buy. And once -- for long-haul pipelines, as you -- as our long-haul systems continue to fill out, that terminal will always offer supply to feed those downstream markets. All right. Let's keep going downstream from Midland. The Midland to ecosystem continues to be supported by long-term commitments. During the past few years, anything that we have done has been kept very, very short-term in nature. We had no appetite to go out and contract capacity as those pipeline spreads compressed. Now earlier in the presentation, I talked about theoretical nameplate capacity. So for us on the crude oil Permian side, our theoretical nameplate capacity is 1.25 million barrels a day. There's about 200,000 barrels a day that's more expensive. So I would call that opportunistic capacity. It's more expensive. In a sense, it takes DRA, its power. And ultimately, the market is going to have to pay more to access it. I don't think that situation is unique to Enterprise. I think it's an industry issue, and you can probably look at the graph on the right and see that as production starts to edge higher, it gets into that capacity tranche. It's going to cost more. Coincidentally, this is also when we have our first contract roll off. So if you were to ask me last year, 2 years ago, I would have told you that crude oil takeaway capacity is overbuilt, over pie. We will never ever need another pipeline again for crude oil. I'll tell you today, it's looking a lot healthier than it ever has been in a number of years. Any repurposing of a crude pipeline by the industry is going to change this calculus. It's not a whole lot different than what Tug talked about with NGLs. Yes. Seaway is another great story for repurposed asset. In 2011, if you looked at this asset, it was a single 30-inch pipeline flowing in the wrong direction. It's going from the Gulf Coast to Cushing. It was also moving less than 30,000 barrels a day prior reversed in 2012. Seaway now stands at 2 twin 30-inch pipelines with the capacity of 900,000 barrels a day from Cushing to the Gulf Coast. If you look at the graph on the right, historically, we had a broader diversity of light and heavy movements, and we're seeing a trend of heavy increase. The Canadian producer continues to make a very desirable barrel for the economically advantaged refineries in the Gulf Coast, and they're signaling future growth through 2030. With heavy being the future of crude destine at Cushing and our strategic partnership with Enbridge, Seaway is positioned well to realize the Canadian growth. Enbridge has expansions upstream of Cushing that align well with Seaway's cost-efficient expansion options and Seaway is going to be ready to capture the future growth of the Canadian producer to provide them access to the Gulf Coast and export markets that they desire. Enterprise got into the crude business through the TEPCO acquisition. At that point in time, we had a gathering system in the Eagle Ford. It wasn't doing a whole lot. We had a gathering system in West Texas. And then we had a small gathering system on the Oklahoma, Texas border. We had a couple of tanks in Midland. We had a couple of tanks in Cushing, Oklahoma. And we had on Seaway 30-inch pipeline that at 1 point in time was doing 30,000 barrels a day. I think you got a walked a barrel of crude oil quicker up to Cushing than that it was moving in a pipe. If you look at where we are today, it's 3 pipelines out of the Permian. The Midland terminal presence has expanded tremendously. The gathering system out there in West Texas has come a long way. We got 2 Seaway pipelines, and all this is heavily, heavily contracted 50 million barrels of storage capacity, access to every Gulf Coast refinery and access to deepwater ship docks. So when we talk about systems, this is a system. When we talk about hard to replicate, this is really hard to replicate. And it's a heck of a system, but we're not done with it yet. We got 1 more thing we want to do. The world has changed a lot in the last several months as the security of energy supply is more and more important. And access to North American barrels is really important. And as much as we thought this was going to be a supply push has also turned into a demand pull. So for spot, which is the 1 project we got left, we want to do. We continue to work through the permitting process. It's difficult but an Enterprise fashion that doesn't deter us. We view spot as a strategic bolt-on to the portfolio of our crude business. It enhances the entire value of that system. It's going to serve as a magnet for production, and it's going to provide our customers with another market choice. What makes spot unique is the type of vessels it can load. It can fully load VLCCs, that's over 2 million barrels a ship. It requires a deeper draft but it is the most efficient means of transporting crude oil on water and efficiency matters more and more as production climbs. Spots can reduce the loading in transit time to and from the ports and it's capable to load at over 80,000 barrels an hour. These barrels have to go further and further away to access market how efficient this gets done is why this project is so needed in this country. It is the most environmentally friendly way to load crude oil. It reduces greenhouse gas emissions by 65% and VOCs by 95%. The market needs it. The U.S. market needs and it needs to happen at our terminal. In summary, the spot terminal will make everything we own upstream more valuable, and it will serve as a magnet for the entire crude system for years to come. Our assets are going to stay full with this asset. All right. And closing on the commercial side. And there's 3 key points that I want all you ought to walk away from when you leave here. Number one, the Enterprise system has unrivaled connectivity and integration, make no doubt about it. It is incredibly, incredibly difficult to replicate. Number two, the value of that existing assets is going up. They are much harder to construct and they cost more money. And #3, the past investments that we have made, go back to the first slide of that map along with these announcements today, the 7 announcements that all these guys talked about, is going to enhance the entire Enterprise value chain and the use of our assets is going to go up -- and continue to go up. And with that, commercial team, thank you all for your time. Thank you.

Good morning. So as Jim mentioned earlier, I kind of left the cat out of the bag a little bit last as to what Project 11 was. Simply put, it's an expansion project to the Houston Ship Channel, but there's a little more exciting story to it than that. It's a 3-step process with to get this approval. The first step is it's got to be congressionally approved. This project was approved in the WRDA 2020 bill, which is the Water Resources Development Act on December 27, 2020. The next step, because the Army Corps of Engineers has so many projects, they have over $100 billion of approved projects, the office of management and budget only allocates certain projects that are allowed to start. On January 19, 2021, this project got one of the only 2 new starts for projects. That's only step two. Additionally, you have to have some form of core funding in order to start a project. The 2021 budget was already out, and there was nothing allocated for this project in it. In the first week of February, the Army Corps of Engineers allocated $125 million to this project so that it could start. In the span of 6 weeks, it went from a dream to a reality through our government. That is absolutely unheard of. And it was accomplished by, if you will, a joint partnership between the nonfederal sponsor and the industry to make that happen. Next slide, please. Simply put, this project is a 6-step project. And what we're going to talk about today is simply step one, the widening of the ship channel from 530 to 700 feet. Next slide, please. In addition to the funding from the Army Corps of Engineers, the Port of Houston has issued $400 million in revenue bonds in order to expedite this project. And with that $400 million and the $125 million, the port expects to have the widening of the ship channel completed by the second quarter of 2024, and that is in record time. Next slide, please. So what does that mean? Two things really. First 1 is it will allow for larger vessels up to 1,250 feet in length to transit the channel and still maintain 2-way traffic because it is a statutory requirement that all vessels on the ship channel have the ability to have 2-way traffic. So you can't just have large ships coming in on a one-way basis. The second 1 is the Houston pilot plan on changing the daylight restriction point from the mouth of the bay to the top of the bay for all daylight restricted vessels. What are those? Vessels over 750 feet in length or vessels carrying hazardous cargo, i.e., hydrocarbons. So this move of 24 nautical miles north will allow for an increased potential of 1,400 additional daylight restricted vessels per year. You gain 4 hours of additional transit time inbound and outbound on daylight restricted vessels. And again, what does that mean? Daylight restricted vessel cannot enter the bay before the sun comes up and has to be out of the bay before the sun comes down. So that's the point at the bottom of the map. They're going to move it to the top of the map. That additional 4 hours each way will bring the potential for an additional 1,400 additional daylight restricted transits to the Houston Ship Channel every single year. What does that mean to Enterprise? When that happens, we can handle an incremental 6 to 7 cargoes per month at our terminal. And as Justin mentioned earlier, one of those low-cost easy projects is we could restart to 1 expansion project and changed that number to 17 to 18 cargoes per month of crude oil or of LPG. Like I said, this is going to be short and sweet because you guys want to take a break. The bottom line to this is not all optimization happens inside the fence line. And pretty much, that's it. Let it be done.

All right. We're going to take some questions now. We're in about 10 minutes or so, and then we're going to take a break. So if you have any questions, we've got mics on both sides of the room, and we can get to you fairly quickly. So who's our first question.

It's Brian Reynolds from UBS. Just talking about Permian nat gas dips and the potential impact on ethane recovery. Tug, you talked about the NGL tightening in Permian in '24, '25. Just kind of curious, you labeled that being conservative? And what are the levers that can kind of pull that forward and the potential ultimately for a seminal conversion down the road.

All right. So I want to answer your question. I'll speak specifically to the NGL component of it. Every day at Enterprise is an exercise of how we can optimize our assets. I'll give you 1 example on Shin Oak. We're able to increase the capacity from 550,000 barrels a day to 610,000 barrels a day just by optimizing the hydraulic profile. So that's 1 option. That's a solution we have in front of us. Seminal is another potential option. We'll address that as the production grows, but we'll be positioned to capitalize on it for sure at that time. I want to be clear, there is no announcement on seminal Day, seminal in crude service.

Okay. Just a general question.

I'm sorry, say your name.

My name is Ben Nederman from NBW Capital Owner. Just a general question, there's a need for all of these projects and they strike me as being bolt-on in nature, highly visible returns. Could you talk about the rate of return in general, how it compares to the overall company? And we're under the impression here that the bars and raise capital efficiency is more important. And are you seeing better returns?

Yes, Ben, I'll take that one. You come in and you look at the midstream, and I've said this for years, you come in and you look at the midstream and the heart of the bell curve on midstream project rates of return are 10% to 15% with some capital-efficient projects, you can do better than that. But I think if you come in and paint with a broad brush, 10% to 15%, that gives you the much of the ZIP code of the returns that we're looking at. There may be some that we can exceed that. Yes. With -- as Jim said, with some upside you hear that, Brent, upside?

I got no problem meeting those returns. Those are good.

Jeremy Tonet, JPMorgan. Two questions. First, just starting off, given how the world has changed. You guys have a lot of conversations with D.C. Do you think that the other side of the aisle is starting to dawn them a bit more the how the world has changed, the severity of the situation, the importance of hydrocarbons? And is that kind of taken hold, do you think that could benefit the industry overall?

Randy says at a glacier pace.

Yes, Jeremy, it's a hard. It will be quite the pivot. I think you've already got people on the Democratic side of the aisle that appreciate the domestic oil and gas production. I think we saw that during the last legislative or the current legislative session that we see that. And frankly, I think it's one of the reasons that you've seen that legislation was really in the build back better when it came into the oil and gas industry. At 1 point, there was talk of do in a way with the tax preference items of the oil and gas industry. But when you come back in and look at what was built in the build back better. Now it didn't get passed when you look at was in that. It kept all the tax -- oil and gas tax preference items in place. So there's a lot of -- a lot of rhetoric coming out of D.C., hard to keep up with it all. But certainly, I think with what's transpired over the last couple of months, the energy security is the new priority.

Got it. Just a real quick second one. You talked about -- Tony you talked about the potential for natural gas egress to impede oil production growth. Just wondering how you see that resolved would Enterprise want to further expand gas takeaway or be a part of a pipe that was a bigger pipe -- a new gas pipeline pipe being built?

The answer is yes, Jeremy. We're -- Natalie is working some projects right now that has the potential to use to do some more repurposing to use some pipelines that are underutilized. We're not ready to go and go there yet. I think she did say we're making sure we have some capacity on our existing. Question is how much do we get part.

Yes. Chase Mulvehill here with Bank of America. So I've got 2 questions. First, I'll kind of dovetail on the last question and probably to Natalie. We were talking about this some last night, but there's obviously been a demographic change about the production profile of growth in the Permian being driven more by private versus public. I think you said -- somebody said today, there was 300 [ m ] a day of uncommitted capacity in 2023. It sounded like you wanted to resell to contract that out to customers as opposed to kind of holding it to yourself and basically making the basis spread and sending some of your own volumes through there. So -- do you -- I guess the question is, is why not hold that to yourself and make the basis spread as opposed to contracting out with some of your customers?

I want to hear the answer to this.

Okay. Now first, I said we're going to use the best for Enterprise, but -- it's a healthy conversation that we have, whether our marketing group or we hold it for ourselves or sell it to our customers. And our customers know the short-term value of that space right now. So it has to be a really hard bid for them to sign up for long-term contracts because they know we're going to have a 10-year take-or-pay type contracts versus us taking it for ourselves for the next 2 years and getting whatever the spread actually ends up being versus what's being printed today. So you can probably that will hold some of it for ourselves. But if somebody puts something in front of us that changes our view. Long story short, we're always about the big E and the best for Enterprise, so we'll evaluate it that way.

Like we have these decisions every day, and it's going to be that long-term owner mentality versus the short-term opportunity. So it's a good, healthy conversation between Justin and Natalie and obviously, there's others involved in that conversation. But as long as we get fairly compensated on what we think value is, then we have no problem doing long-term deals. We like to do long-term deals. That's our history. But there's probably other projects that we have also, and we want our customers to make money. That's -- they should make money. But we just want to make sure that we get our piece too. And so -- anything that we can do upstream that helps the value chain if we have to go contract that capacity, I can tell you this, it will be to the benefit of the entire value chain if we go forward with that.

Okay. One quick follow-up. Just obviously, you announced a lot of projects here already getting quite a few items about the CapEx, and the phasing of how much it's going to be. So I don't know if you can kind of lay out the CapEx plans, the phasing of kind of how it looks over the next few years?

If you can be patient with us. I think Chris is going to lay it out completely in his section.

Rebecca Followill, U.S. Capital Advisors. Brent, your messaging was that there's -- volumes are going to fill up. You've got a system that's got a lot of unutilized capacity it's going to fill up. Can you quantify after years of kind of stable EBITDA and now going into growth, if you fill up the assets that you have, what kind of incremental EBITDA it adds to you?

And you listen we're going to give guidance back.

I'll tell you what my goal is. Last year, I think Brent and I had to of making an $8.5 billion EBITDA, we came in at Chris, did we get it or we were right there at it. Just under it. My goal is I want to be -- I want to -- I'm tired of 8. I want to see 9. And I don't have that many years left. And God, we're going to get to $9 billion plus EBITDA. Does that answer your question?

Not really.

Beck is hard to satisfied, yes.

I think we'll come in and give you some visibility on the CapEx in Chris' section. Nothing surprising. It's consistent with what we've said in earnings call. And I know you guys are good at spreadsheets. And if you look at 10% to 15% returns and you just add it on to what we've got. And we can come in and fill up some additional capacity. That's why you guys get paid the big bucks. It's come up with an earnings forecast.

Keith Stanley with Wolfe Research. I'll speak a little louder. There we go. Two questions, if I could. First, on Navitas. I mean you talked about liking the commodity exposure. Is there a framework you can give on how much it increases the company's commodity exposure in terms of equity NGL volumes? And then likewise, you're very bullish commodities, would you look to potentially other tuck-in GMP type acquisitions that can further add exposure to the business?

Justin, do you want to hit the commodity upside?

Yes, I'd say on the NGL piece, it probably adds another 20,000 barrels a day of exposure and add on top of that a little bit of residue, call it, 75,000 a day.

Then on natural gas.

Yes. residues.

So core them how about condensate on the NGL number. Okay. In terms of -- who answers that question. Okay. In terms of other M&A, I think, first of all, we're going to digest Navitas. And I love what Randy says about M&A. Price matters. Natalie said, we looked at different systems. I will tell you, we think we picked the cleanest system out there, the 1 that gives us the most downstream potential integration and the 1 that we thought the quality of the assets that she said, these guys, I'm not convinced the management team wanted to sell. They were building a business and we like the business. We like what we acquired. As to other ones, we've got a lot of projects on our plate. And it's going to have to be something that gets our attention.

Jean Ann Salisbury from Bernstein. I just have 1 you showed that most of your LPG export capacity, the contracts are rolling off in the next few years. Obviously, the rate that people have been willing to pay has kind of been coming down over the last few years now that we're approaching capacity again. Are you seeing that rate that people are willing to pay go back up? And if not, would you kind of consider keeping it open and taking the ARP if you expect that to lighten.

I'd say we're just now starting to get into 2023 contracting. But as the gaps kind of illustrate, we feel pretty good that our available capacity is going to be worth more as we get down into '24 and '25. So we'll probably hold out for something probably higher than historical what it is, we'll kind of let the deals themselves, work themselves out, but I feel pretty good about it.

I'll say this for those 1-year or 2-year contracts, it can't go any lower.

Yves Siegel, Siegel Asset Management Partners. Tony, I hate to push back on you, but you said that you haven't seen the producers indicate that they're going to pick up activity. And I think Jeremy asked the question too about the administration and just the regulatory side. So what gives you confidence that we'll see increased activity and we'll be able to get permits and get things built that we need to get built.

That's a good question. When you look at our production growth Yves, greater than 90% of is in the Permian Basin. So the only fly in the ointment there that people have been perceiving is will producers be able to get permits out of the Delaware Basin. And under this administration, they have been. When you look at the pipelines that are needed, they're in Texas, they're not interstate pipelines. So they will be built, Tug will build these pipes, Natalie will build plants, that's what gives us the confidence. If it were Appalachia, I would feel very different, there's a problem and I don't have any confidence that they're going to get a substantial amount of more product out of Appalachia, that's the harsh reality. But it's the Permian Basin.

Okay. Good questions. We'll have another shot at questions at the end of the presentation. We're going to take a break now. We got about a 10-minute break, and then we'll ask you to come back and we'll get started on our next session. Okay. [Break]

Okay. Okay. If I could get you start working yourself back to your seats. We're going to get started. Okay. We'll go ahead and get started with our next panel. Graham, I'm sure you'll introduce everybody. This is Mark Tono?

Okay. Good morning. Thank you for being here today. My name is Graham Bacon. And today, you'll hear from Chris Pipkin, our Senior Director of Safety; Angie Murray, our Senior Vice President of Technical Services; and Magnus Olson on my far right, our Vice President of Supply Chain Management. Last year, we had another great year operationally, including our best safety performance ever. You'll hear from Chris on some of the details on how we accomplish that and some of the initiatives we have going forward. You'll hear from Angie a little bit about some of the initiatives we started last year on operational efficiency, particularly around our pipelines and our facilities, and she'll go into more details on -- now we've continued to sustain and improve our overall efficiency and where we're going to take the next steps that we'll be taking. And you'll hear from Magnus on supply chain and how Enterprise is managed a number of the supply chain issues that have began to emerge last year and are continuing along, along with the inflationary impacts that we're seeing and what Enterprise approach has been to that -- to managing those situations. But in Enterprise, we always look on the operations side, we always like to start with safety first. And if -- the slide that you see shows that last year was our best year ever from a safety performance perspective, and we've continued to drive down our overall incident rate. And I'd like for Chris you could explain a little bit about some of the programs we have in place and how we're going to keep improving on this.

Sure, Graham. Thanks. 2021 was, in fact, our best year on record with respect to total recordable incidents. What we realize that total recordable incident rate is really just a number. It's about our people, our training, our programs and our processes that really drive these numbers. And we believe that by setting expectations and then leading by example, we can continue to improve upon our safety performance going forward. Our safety culture starts at the top. Randa, Jim and Randy are actively engaged as safety leaders, and this is evident across the entire organization. Others seek to follow their lead such that we have safety leaders at every level within the organization. And this is really a fundamental way that we do our business. Our cardinal rules of safety identify the highest risk to life safety that we encounter during our daily work task. And we believe that if we focus on our cardinal rules of safety, we can eliminate significant incidents. Our cardinal rules of safety really set the fundamental safety expectations for the entire organization. To ensure that we're following our cardinal rules of safety, we perform audits. Any action items or findings during these audits are documented and tracked to completion, such that we can be sure that we close any gaps that might exist. In addition to this, continuous mentoring and continuous training, ensure that our people know, understand to get practice our cardinal rules of safety, and we believe this will lead to continued safety improvement going forward.

The incident rate we show is just 1 measure of our safety programs effectiveness. And really our programs are generated, more to prevent the catastrophic life altering, business altering, business disruption, altering incidents that can occur in our industry. And one of the keys to that is our integrity programs, both our mechanical integrity programs and our pipeline integrity programs where we spend hundreds of millions of dollars a year to ensure the integrity of our asset. And Chris, you've got a background in mechanical integrity and our mechanical integrity programs, and they're really core to our safety program. So why don't you describe that in a little more detail for us.

Sure, Graham. We'll be happy to -- my time in both our asset integrity program as well as our safety program, really led me to see how integrated safety is into all of our programs at Enterprise. We talk a lot about recordable incidents, and that's really important. But our Asset Integrity group is actively engaged to ensure that we achieve our goal of 0 significant incidents, which can lead to large business interruptions and large losses. And our Asset Integrity group uses our safety data to help drive the focus of their programs. As an example of this, an incident that occurred in 2016 at our Pascagoula gas plant, led us to investigate the failure mechanisms in our brazed aluminum heat exchangers. We use industry data as well as our own internal incident data to help develop an integrity management program that we rolled out to brazed aluminum heat exchangers across our entire asset base. Today, we're considered an industry leader in the way that we evaluate our brazed aluminum heat exchangers and we believe that we're an industry leader in the way that we use our safety data to continually improve all of our programs.

One of the keys to Enterprise's culture is collaboration and the way that our Safety group collaborates with our engineering groups, our operations group have really led us to be able to drive that increased -- that improved performance, and we're going to continue to drive that. Another area where we've really been driving performance is some of our operational efficiency initiatives. Last year in the presentation, Angie talked a little bit about some of the initiatives that we had just started. They're really yielding fruit right now. And I'd like for Angie to describe some of those initiatives that we've undertaken and where we stand.

Yes, I'm happy to, Graham. I'm really proud to report that our data-driven operations efficiency initiatives are going very well. We've made a lot of progress over the past year. By leveraging the investment that we've made in data processing tools as well as the cross-functional team that we put in place, we've been able to build out optimization models for all of our targeted pipeline systems and over 90% of our fractionators. And these models give us daily insight into how we're performing against the historical operations as well as the theoretical optimum. And this allows us to make daily optimization decisions that, over time, accumulate into step change improvements. And we regularly measure our performance against historical data and our performance has really been outstanding. Through these initiatives, we've been able to see significant improvements in our operating efficiency as well as our profitability.

Yes. I think some of the things that, that group has done, I had some expectations when we started out and her team has really been unleashed and taking that well beyond my expectations. But you're also working in a number of other areas and have taken on a number of initiatives -- new initiatives this year, one of those.

Yes, that's right, Graham. So what we've done is we've really challenged our entire organization across all areas to think about the massive amounts of data that we collect each and every second. And how we can unlock that data to provide information that leads to better decisions. We've also implemented a small but impactful team of data scientists who built out the tools that support each group's unique vision and need. And we have a wide focus area. Chris already talked some about what we do on the safety side. And I just want to add to what he said that we've also built out machine learning models that are aimed at keeping our assets safe. We, of course, have a huge focus on cost reduction, and I've talked a little bit about that already. But another neat area is we analyze real-time power pricing, and we adjust our operations based on that pricing, really driving down our energy utilization costs. And then we use data analytics to assess our procurement spend across the organization. And [ Magnus ] will talk more about that in just a minute. We have a huge focus on reliability and using data to drive the improvement in the reliability of our assets. And we also look at our mission sources. And we look for anomalies and emissions, looking for areas where we can reduce and in some cases, fully eliminate emission sources. And a great example of this is what we do with hydrogen, where we've been able to find opportunities to use hydrogen as a fuel, displacing the needs of our natural gas.

Yes, one of the things that every company has initiatives and take those on. But one of the keys to making them really to continue to generate those savings is to make them sustainable. And I think that's where it's easy to trip up. What's your team done to make sure the savings that you've achieved are going to be sustainable?

That's absolutely right, Graham. Sustainability is really critical to the success of these efforts. And I've been personally very impressed with the way our organization has embraced the use of data to drive sustainable improvement. And I think this is for several reasons. One, we have clear support from our leadership; two, we have metrics in place to measure the results. But in the end, I think it really comes down to our people. And I think the success has been a result of giving our decision-makers, the tools, the knowledge and the ability to make better decisions. And a great example of this is what we do in our pipeline control center. Where our pipeline operators can see on the screen where they operate the pipeline, the cost of operating that asset. And when they change the operations, they see immediately the cost impact of that change. They can also pull up a screen to trend the cost over time, allowing them to measure their own performance.

Yes. Having that available to the controllers, I think, has been a game changer. First and foremost, their job is really to ensure the safe and reliable operations of the pipeline. But when we put that additional information in them on how much it was costing to operate a pipeline, it really led to a lot better decision-making, a lot better engagement. And it's not only good for cost performance, it's good for overall emissions performance and a lot of things. But really, the engagement -- and Brent talked about this earlier about how we think like owners, and it really got our controllers thinking more like long-term owners of the pipeline and really encompassing another dimension. And I think that level of engagement has been fantastic. What else are you seeing as we've unleashed some of these on how we're seeing better engagement.

Yes, I agree, Graham. The level of engagement and ownership since we've gotten these tools in the hands of our employees has really gone up and it's exciting to see. And if you think about it, it makes sense because when each person understands the impact, their daily decisions have on the bottom line, and we make that visible to them and immediate for them to care more and they see how they're making a difference. And the reality is they're really making a big difference.

Yes, we've talked a lot in generality so far. But why don't you go and talk a little bit more about how big a difference we've seen over the last year.

Okay. I'm glad you asked, Graham. The operating efficiency initiatives have -- they really lead to lower cost, lower energy utilization and lower emissions. And so starting with the cost side, we've seen a cumulative cost savings of over $100 million as a result of these initiatives. We've also been able to drive down our energy utilization by the equivalent of 45 megawatts per hour. And just as importantly, our direct greenhouse gas emissions have reduced 13% over the past 2 years and our emissions intensity has steadily declined over the long-haul. So I'm really proud of the results that our teams have been able to accomplish by leveraging these data initiatives. And I'm looking forward to finding ways to continue to make them sustainable and to find new ways to unlock data to drive additional improvement.

Yes. Your folks have really done a great job in working with -- again, at Enterprise everything is a team approach, but you'll have really driven a lot of improvement over the last year. Let us switch gears a little bit, talk to Magnus. I think a few years ago, I'm not sure a lot of people really knew what a supply chain was. Now you can't pick up a paper or hear the news and not hear supply chain. I think sometimes even your kids [ will know ] what a supply chain is when you can't get them something. But Magnus is going to tell us a little bit about what we're seeing at Enterprise and some of the inflationary impacts that we're seeing and how we're managing that. Magnus?

Yes. Absolutely, Graham. I appreciate it. We continue to see inflationary pressure and supply chain constraints out there. But we have an enormous effort and focus here at Enterprise to mitigate any impact. But first, I want to start off giving you our outlook and some of the key commodities that we track that really impact the cost of the goods and services that we procure. And if you look at the slide deck up here, you're going to see metals. And we expect to see these prices peak this quarter and stabilize as 2022 goes on. However, that could obviously change given the geopolitical situation and the war in Ukraine. Similarly, if you look at line pipe, prices peaked at the end of 2021, came down fairly rapidly at the beginning of the year because demand for line pipe was down. However, our outlook on this is probably a little more uncertain. There's a lot of volatility in the steel market currently as well as for the commodities that are used in making API steel. When it comes to labor and for finished goods, now we're talking pumps, valves, motors, transformers. Graham, we expect to see those prices increase through 2023.

Yes. We struggle putting some of these graphs up because the pricing change pretty rapidly. Earlier in the year, there was a lot of talk and late last year talk of some of the inflationary aspects being transitory, but the last few months have kind of shown us that this is probably going to be around for a while. Magnus, I'd like you to go into a little more detail on how we've managed to control our cost and some of the inflationary impacts that we're seeing.

Yes. Absolutely, Graham. We took a lot of proactive steps, and we've really started this during the downturn. So what we're doing is we're continuing to leverage the size and buying power of Enterprise to really help improve upon our pricing. And we're using spend data and market intelligence. And you heard Angie talk about data, and we're big users of data as well that really helps us making go/no-go buying decisions. When it comes to the rising cost and labor, we fixed a lot of our T&M contracts on multiyear contracts, a lot of these going out 2 to 3 years. We went ahead and pre-bought materials to offset price hikes as well as the long lead items. We also started looking at increasing inventory levels of critical items. And then we manage those items efficiently between the regions. We also have strategic contracts in place with critical suppliers and this is for sure, it is supply. And we're also looking at diversifying our supply base. And last but not least, we utilize index-based contracts with caps, and that's really helped us mitigate and minimize exposure in a volatile price environment.

Yes. I think your team did extremely well getting out in front of some of these. But obviously, those -- some of those decisions that were made last year, bearing fruit this year. What are you doing to get out in front of it and continue to make this happen?

I'm really proud of the efforts that we have so far as an organization and our ability to control and contain cost. So we have several new initiatives underway. We're certainly not sitting still knowing that this is kind of a volatile and ever-changing environment. And we continue to utilize data. We continue to leverage knowledge and market intelligence, not only within the supply chain organization, but across the entire organization, whether it be technical service, operations, commercial, et cetera. And that really helps us making better, smarter procurement decisions. But I think at the end of the day, it really comes down to our people, being focused, utilizing data and proper planning to kind of get ahead of the issues. And I think this approach has served us really well in our ability to respond to events such as Winter Storm Uri, Hurricane Ida. So it's leveraging our existing relationship, leveraging Enterprise's size in buying power, using data, proper planning, and that helps getting our assets up running safely and reliably, Graham.

Thanks, Magnus. Chris and Angie and Magnus talked a lot this morning about some of just a few of the things that we've got going on to -- in our operations area to sustain and continue to squeeze out what we can out of the assets and make them as efficient as possible. Obviously, as Brent and his team talked this morning, we'll be building new assets and bringing those on. But our drive is, from an operations perspective, as always, to continue to improve and really drive performance to be the premier midstream operating company. We talked a lot about data today. And data is important, but the data is only there. It's what you do with the data. And we've got great people that know how to take that data, analyze it and turn it into actionable items to really drive the improvement to the levels that Angie mentioned. Magnus also touched a little bit on Winter Storm Uri and Hurricane Ida. And the things that we did there were really to ensure that we were able to be ready to take product and meet our customers' needs when they were ready, and we were there. And that's a consistent pattern with Enterprise, whether it be floods. We talked to Harvey hurricanes, pandemics. We're always there and ready to meet our customers' need and to be the reliable provider of services. We don't always know when, where or how those events are going to happen. We do know that they're going to occur. They're just part of doing business. But what we do know is our people will always be prepared. They'll be ready to respond and be able to deliver and meet the needs of our customers. And that concludes our presentation. We thank you for your time.

All right. So I have the pleasure of hosting this panel today, and I thought maybe the right place to start with this conversation was with Tony. Tony had a pretty bullish supply forecast for hydrocarbons for the next 3 to 4 years. Thinking longer term, how do you see the demand for hydrocarbons over the next 3 to 4 decades?

Yes. So let's go to this slide, and I know it looks pretty busy. There's a lot of lines and colors on it, but it's really pretty simple. What we're doing here is taking a historical and projected look at population and energy trends. From 1990 to 2020, so the last 30 years, we grew our population 2.5 billion people, up 50%. Energy consumption during that same time period was up about 85%. The graph on the right shows that over the next 30 years, we're going to add about 1.8 billion people. Randy talked about that this morning. Most of those people are going to be born into energy poverty. And much of the 2.5 billion that we added over the last 30 years still live in energy poverty. But that's the reality. Some will tell you that we're going to put this amount of people, this 3 billion plus people that live in energy poverty plus those are coming that we're going to put them on renewables. But the facts are that, that technology really doesn't exist. The reality is, according to CDP, only about 35% of the pledges that have been made are backed by credible science-based initiatives. Our own research shows that you add scalability and profit on top of that. And this is a tall order. So how do we square that circle for all these people that are coming. And we believe that the answer to that is all of the above, again, as Randy talked about this morning, that's likely where we're headed, that's where all the signs point to. So let's go to the next slide, and let's just look at oil consumption. So where do we use it? We all know that it's about 100 million barrels a day, but where do we use it? So there's the industrial number for cement, steel and et cetera. There's petrochemicals. I've put feedstocks by that because generally, that's what it is. There's your residential cooking and heating. We've made some great strides in that regard with natural gas, with LPG and to some extent, electricity over the years. Energy transportation, 63 million barrels a day, about 64% of global demand. And then we have that broken down into passengers and trucks and buses. If you go to that far right-hand column and you look at available economic and scalable technologies, you don't see very many yesses there, and that's the challenge. I don't know the number exactly, no one does, but probably greater than 60% of current oil use as we see it today has no available alternative, much less from an economic standpoint. And that's where our evolutionary technology team comes in. And I mean this to the two of you. I have Carrie Weaver here and she heads the commercial part of that team. Angie Murray, who you just heard from me, heads the technical part. But you all really don't -- if you're trying to separate, you don't do a good job in that respect, you'll work so closely together. It's very impressive. But I would tell you this, and I mean this, I am very, very impressed. I think you have the brightest, most creative minds in Enterprise on your teams and hats off to, I mean, all in that regard. But that's what it's going to take. It's going to take thinking outside of the norm and figuring out how do we add value in this regard. Let's go to the next slide. If you look at what we do, we have 4 core competencies. We gather and reprocess, we transport. We upgrade and after we upgrade, we segregate and then we store and we distribute and we export. Those are our core competencies. I think Chris did a good job, and he's done the last job -- a good job the last several years of explaining to you how we're going to take the typical midstream oil and gas model and how we've converted it to providing petrochemical midstream services. When I think about the opportunities that you all look at, we're going to take the same core competencies, it's my guess and you're going to expand those into low-carbon midstream services. And with that, that's how I see the fundamentals over the next, call it, 30 years, Chris?

That's great, Tony. So I guess with that in mind, Angie, can you talk a little bit about what the evolutionary technologies team has been up to over the past year and some of the areas that you're focused on?

Yes, absolutely, Chris. We formed the evolutionary technology team almost a year ago with the goal of identifying opportunities to address our own carbon footprint as well as to provide solutions for our customers to meet their environmental goals. And it truly is a unique team, half commercial, half technical. And as Tony said, with the brightest and most creative minds, and I agree with that, sitting side-by-side, sharing ideas and collaborating on solutions. And we've evaluated a wide variety of areas over the past years that's allowed us to hone in on 4 key focus areas: carbon capture and storage, hydrogen, low-carbon fuels and circular products.

Well, then, Carrie, I guess from a commercial perspective, can you let us know how these low-carbon initiatives are going to fit within the broader Enterprise business framework.

Sure, Chris. In each of the 4 areas Angie mentioned, our focus is on projects that is profitable and complementary to our existing business models while advancing [indiscernible] driven economy for ourselves and for our customers. And to echo point that Jim and Randy made earlier and Tony just made in the intro, we don't see these low-carbon solutions as replacing traditional hydrocarbons or compromising the services we provide today. We see them as additive complementary solutions that help supplement production growth in environmentally sound way while capitalizing on our existing energy infrastructure.

Yes, that's right, Carrie. And to add to what you said, for example, low carbon fuels and circular products are basically drop-in products that are compatible with our existing infrastructure, and they can be used in conjunction with traditional fuels and feedstock. So this allows us to meet that growing demand with our existing assets. And similarly, carbon capture and storage and using hydrogen as a fuel are bolt-on solutions to decarbonize our existing infrastructure, not replace it. And that's true for our own assets as well as for the broader industry.

Yes. And Chris, successful implementation of the bolt-on and drop-in solutions that Angie described, will all require things like processing, transportation, storage, distribution, all of which we do today. And we now just like to expand those across a new platform of low-carbon midstream energy services. And by leveraging our assets, our experience, our reputation for reliability and our long-standing customer relationships, Angie and I believe that Enterprise is a natural fit to provide these services for the growing world.

So then maybe starting with carbon capture and storage. What is Enterprise doing to reduce its emissions footprint and promote a clean energy future.

Yes, I'll start with that, Chris, and say we definitely see carbon capture and storage playing an important role in decarbonizing our assets. There are approximately 6.6 billion tons of CO2 equivalent emitted in The United States each year. And of those, about 1/3 are good candidates for carbon capture and storage solutions. And those emissions that are highly concentrated in the industrial sectors of the Gulf Coast and Mid-Continent providing great opportunity to aggregate and sequester at scale. And handling CO2 isn't new to us. We operate [indiscernible] treaters at over 30 of our gas processing and treating facilities and [indiscernible] treater's primary purpose is to remove CO2 from the gas and NGL stream. And this is really the key technology that's being deployed today in most carbon capture solutions. I also want to point out that at our Delaware Basin gas plant we capture, transport and sequester CO2 from that facility today, and we have successfully done this over the last decade. We're actively pursuing projects to replicate this at our existing assets as well as to provide our customers solutions to do the same.

Yes. Chris, I'll expand upon that last point a bit more. Since we formed this group, one of our main focuses has been to meet with customers to understand their goals and collaborate on solutions. And between our commercial side and our technical side, Angie, I'd say we've probably had well over 1,000 meetings with companies. And one of the main topics we discussed in almost every one of these meetings is carbon capture and storage solutions. And so by investing the time meeting with customers, we've been able to identify target opportunities that we're actively progressing today. And in those service offerings, we see Enterprise playing 2 key roles. One is in the aggregation and transportation of CO2; second, in the storage of CO2. So to the first one, today, we aggregate and transport oil and gas from the wellhead or petrochemicals and refined products from industrial complexes. Tomorrow, we look to adapt those service offerings to CO2 from emitters [indiscernible]. We really doesn't look much different from what we do today. And on the storage side, we're evaluating opportunities to provide the service ourselves, but we're also in advanced discussions to align with the strategic partner who mirrors our experience and reputation on the subsurface side to provide the service. We're hoping to have an eighth announcement today, but Justin said that was too many. We'll look to provide more details on this in the near future. And back to the meetings I mentioned. The resounding message that we're hearing is that these solutions need to be reliable and economic. And that economic component can be challenging with the current incentives. If you take a look at our map, what you'll see is our extensive asset footprint is positioned along the Gulf Coast and overlays very well with highly concentrated sources of emissions along the Gulf Coast. And what that means is that we're ideally positioned to provide reliable and cost-efficient solutions by leveraging our assets to evaluate and identify repurposing opportunities. Our experience and capabilities constructing and operating pipes, especially in some of these tight industrial quarters. And finally, our reputation with the industry to help bring scale to a project to find these cost-efficient solutions.

Great. Thanks, Carrie. And I think we'll probably circle back to some of those capital projects here in a minute. But before getting into that, Angie, if we're not really dealing with carbon capture, what about hydrogen? Is that the next area that we're really looking into?

Yes, Chris, we definitely see low carbon hydrogen playing an important role in decarbonizing where, for example, electrification or carbon capture and storage may not be the right fit or it may just be too costly. And I'm sure most of you know that today's primary demand source for hydrogen is refinery applications and industrial processing. But in order to decarbonize, hydrogen is expected to be used in new areas such as transportation, power generation and for heating, for example, in industrial furnaces and potentially even residential heating. But in order to support that growing new demand source, there's going to need to be an infrastructure build-out. And that will need to come in areas such as pipeline transportation, storage as well as the hydrogen production facilities themselves. And having said that, we do see carbon capture storage playing a complementary role to the production of low-carbon hydrogen, which you probably commonly here referred to as blue hydrogen. I know Natalie talked about that, and there's a lot of pickup in the industry right now around this. And that's where the CO2 that is emitted from the hydrogen production process is captured and sequestered.

Yes. And I'll add a great benefit of a hydrogen solution is that low carbon hydrogen can be produced from the natural gas that we have right here in The U.S. and then distributed domestically or exported to country looking for alternative low-carbon fuel sources. This further bolsters our energy security while also expanding The U.S. energy economy. I think you mentioned it, hydrogen is a drop-in or additive solution. It can be blended into natural gas and consumed as fuel and industrial facilities using our existing infrastructure and equipment.

Yes, that's right. And since you mentioned blending and Chris, I know you get asked a lot about there's -- the many studies that are going on right now in the industry about the potential to blend hydrogen into natural gas systems. But for our assets, we see the potential to blend up to 60% of hydrogen in natural gas for certain applications. And a great example of this is what we're doing today at our Mont Belvieu facilities where the hydrogen that's produced as a byproduct from our dehydronization unit is used as fuel at our fractionators. And this is a 0 carbon fuel that was introduced into our assets with minimal capital cost. We're applying this same concept in our PDH 2 facility. And when that facility comes online next year, its emissions will be almost 90% less the notes of PDH 1.

That's a great example of success we've seen with hydrogen. And I think a way to expand this and grow our customer relationships is to provide them access to hydrogen so they can replicate what we're doing at Mont Belvieu. So if hydrogen becomes cost competitive, we envision utilizing our existing natural gas system blending and hydrogen at target locations and supplying this low carbon fuel to our customers. It's a cost-efficient bolt-on solution and service to what we do today. But as you heard, to fulfill this growing appetite for this versatile low carbon fuels, it will require a ramp-up in hydrogen production and a significant build-out of infrastructure. Well, Enterprise has the natural gas supply, and we have the infrastructure to support the hydrogen production. And so we see a natural extension of our value chain and our service offerings could be in the production, transportation, storage and distribution of hydrogen domestically and internationally. All of these things are part of our 4 core competencies. And again, we'll look to our existing assets, that being our pipes, our caverns and our export infrastructure to identify repurposing opportunities to take advantage and find cost-effective solutions.

Starting to pick up on a theme that we're going to constantly repurpose our existing assets. Okay. Well, great. I think that covers off CCUS and hydrogen. Angie, you also mentioned earlier that we're looking at circular products and low carbon fuels. What are we doing with those areas?

Yes, Chris, we definitely see these areas as the most straightforward opportunity to introduce into our assets with minimal cost. And since you mentioned the theme for low carbon fuels as an example, this is really just a drop-in product that is -- can be used in conjunction with traditional fuels, for example, refined products on our existing assets as they are today. So we really see a great synergy in extending our existing transportation, blending, storage and export services to these new emerging fuels. And this might be in the areas, for example, renewable diesel, propane, natural gas and sustainable aviation fuel.

Yes. And it's a very similar story on our circular product side. Currently, we provide trucking, terminalling and pipeline transport logistics for [ pile ], which is oil produced and chemically recycled plastics. And we're exploring, expanding those service offerings, potentially creating market hub similar to what we've done with ethylene and propylene. And Chris, in this area, it's all about integrating new products into the existing assets and services we provide today. This enhances the long-term optionality of our assets, also creating an affordable avenue to bring these high-demand, low-carbon products to market.

You guys have certainly done a good job of defining what the opportunity set looks like. But what about the challenges? What are some of the things that are impeding some of these projects actually getting done and commercialized?

Yes. While we do see opportunity for some of these projects today, we also think that there needs to be advancements in areas such as technology, regulation and policy. And so starting with technology, and Tony talked some about this earlier, but we've evaluated thousands of technologies over the past year. And while some of them are commercially viable today, many of them are in the very early stages of development. So they need to go through additional pilot testing, demonstration units, scale up commercialization in order to be viable. And that just takes time. And then on the regulatory front, companies need assurance that there will be a regulatory framework in place to support this infrastructure build-out. And that may come with permitting support, for example, for classic, well, for CO2 sequestration or permitting support for a new pipeline, for example, for hydrogen transportation.

I'll jump on the policy side. To me, being the commercial person and having the discussions with commercial customers, one of the -- some of most important is that these solutions are economic and able to compete with traditional fossil fuels, so we can continue to provide affordable energy to people everywhere. And so this may come from government grant to help support technology innovation and scale up, it could also be from expanded government incentives, increasing 45Q, providing direct pay or expanding the low carbon fuel incentives. And with these challenges, it's all about finding solutions that are reliable, scalable and affordable. And Chris, even with these challenges, we've identified opportunities that work today. And for those that don't, we believe the opportunities outweigh the challenges. And so the right developments in these areas will come to further support cost-efficient solutions at scale and really motivate further investment down the road.

Okay, Carrie. I told you I was going to circle back to this, but you mentioned that these projects need to be economic and competitive with existing projects that Enterprise is working on. Does that mean that Enterprise is not going to pursue a project that has lower returns than what we've historically earned? And can you expand a little bit more upon when we think we may have a commercial project announcement.

I guess I walked into that one. The thing is, Chris -- so we're taking a disciplined approach to this. we see successful projects looking like an evolution of our existing service offerings. The most attractive opportunities will be synergistic with our existing infrastructure and capabilities really built upon those 4 core competencies that we've touched on throughout our discussion today. And the projects that we pursue will be supported by long-term fee-based commitments that meet our normal return threshold. So I'm sure you're happy to hear. And so we are actively in commercial discussions with substantial players. And we do see some of these opportunities progressing in the near term. All others of those are longer-term awaiting developments in the areas that Angie and I just spoke of. But for those that are longer term, Angie and I have -- goal is to be ready to deploy capital projects when our customers say go.

Yes. And when they do say go, I have no doubt that we'll be ready with the team we have in place. Carrie and I truly believe that if anybody can do this, Enterprise can and we will continue to work with diligence and speed to execute on our vision to be the future of midstream, providing sustainable value to Enterprise and our shareholders. And finally, I want to circle back to something that Jim and Randy mentioned early on and Tony talked about as well because I think it's really important. And that is, we need an all-of-the-above approach to support the world's growing need for energy while also advancing low-carbon solutions. We provide these solutions today, and we will continue to evolve and grow and leverage our assets, our experience and our reputation to extend these solutions for the future.

Great. With that, Tony, Angie, Carry, thank you very much. We look forward to more projects coming out of this group.

Thank you.

All right. We're down to the last section of the day. Maybe before we jump into the financial numbers, Daniel, given everything going on in the world with geopolitical events and constant threat of cyber attacks, maybe take a couple of minutes and remind everyone what Enterprise is doing to protect our network and critical infrastructure.

Sure, I'd be happy to, Chris. Yes, threats from cyber risk have really reached an unprecedented level. We expect that to continue as criminals and bad actors become even more motivated and sophisticated. Colonial Pipeline in May of last year provided a good case study on some of the things that we could expect some attack on our industry. And fortunately, we had implemented multifactor authentication, the automated purging of an active user accounts well before the Colonial incident occurred. Since that time, at Enterprise, we've more than doubled the size of our cybersecurity team. We've implemented some strengthening measures of our own as well as those prescribed by the various government agencies. And we've collaborated with our business team to develop a more robust disaster cyber recovery plan in the event of an attack. Our current focus includes additional hardening measures. We are continuing our migration towards the Zero Trust framework, which really involves tightening down user privileges and securities. And we also have opportunities to segment our systems, whether they're the networks or other devices in order to leverage those -- just a tighter network where it makes sense. Although we've made a lot of progress in the past year or so, I doubt we'll ever be able to say we're finished. This is going to be a top area of focus for us now and for many years to come. So moving on to the financial highlights. In 2021, Enterprise reached $8.4 billion in adjusted EBITDA. And driven by the rebound in the global economy, we reported 12 financial records and 5 operational records and 3 of our 4 business segments reported record earnings. Our net leverage ratio was 3.1x, and we generated $8.5 billion in cash flow from operations, up from $5.9 billion in 2020 as working capital requirements necessary to fund the significant contango opportunities, Jim alluded to earlier, subsided.

And then as you may recall, back in 2017, Enterprise is on a path to be able to fund its growth capital expenditures, its distributions and its buybacks, all from internally generated cash flow. We accomplished those objectives in 2020-'21, having earned $2.2 billion of discretionary free cash flow. And as Daniel pointed out, we did all this while maintaining a very healthy balance sheet and we then utilized that balance sheet strength at the beginning of this year when we made the $3.25 billion acquisition of Navitas.

If you look at our business segments on a combined basis, they generated $8.6 billion of GOM in 2021. Our NGL segment, which includes our gas processing activities contributed just over half of that total. Our petrochemical and refined products segment continues to march higher each year. It achieved a record gross operating margin of $1.4 billion last year. And that was due to a huge contribution from our petrochemical services business. It reached $1 billion GOM target that we had established really 3 years earlier than the date we had initially set for achieving this milestone. As I mentioned previously, Enterprise set 5 operational records that you can see listed above. And we also placed a number of new projects in service. Those included our C5 hydrotreater, additional ethane transportation capacity from Mont Belvieu to Beaumont and several different projects to supply feedstock to the growing petrochemical plants on the Gulf Coast. We also placed into service the Gillis lateral and Natalie described, which supplies natural gas to various LNG export facilities at a time where it's needed more than ever. And then finally, our commercial team partnered with ICE and Magellan to develop the new ICE HOU contract. This provides a far more relevant and hedge effective tool for producers, refiners and exporters to use -- to hedge their positions. And as Justin mentioned earlier, we expect to see both upside and downstream benefits from that new contract.

And then earlier this morning, you heard Brent and the rest of the commercial team talk about our integrated asset footprint in our value chain approach developing infrastructure. It's the combination of these assets, along with our commercial team's ability to capture value that are really been driving force behind this operational performance that Daniel just went through and results in the financial stability represented by the 4 graphs on this slide. So despite a global pandemic, negative crude prices, extreme weather events, Enterprise has continued to be able to grow its cash flows, both on an absolute basis and on a per unit basis. We've also responded to changing market conditions. We've reduced our growth capital spending by 57% since its peak in 2019. And then as Daniel mentioned earlier, we ended 2021 with a net leverage ratio of 3.1x, which was one full turn below where it was just 5 years earlier. This operational performance continues to deliver one of the strongest balance sheets across the midstream infrastructure space. So far in 2022, we've already increased our cash distributions by 3.3% on a year-over-year basis. We've retired $1.4 billion of senior notes that matured back in February. And again, as I mentioned earlier, we made a $3.25 billion acquisition in Navitas, utilizing only cash on balance sheet and commercial paper. Adjusting for those events, our pro forma year-end 2021 leverage would have been 0.03x a turn higher at 3.4x, and our pro forma adjusted liquidity at year-end would have been still in excess of $2.5 billion. And then as you can see on the graph on the right side of the page, Enterprise has no additional senior notes maturing for the remainder of 2022 and a very manageable maturity schedule for the coming years. And what this does is provides us a lot of financial flexibility with how we think about funding some of the growth capital projects. So with respect to growth capital projects, earlier this morning, you heard the commercial group talk about 7 new projects that are very capital efficient, that are either adding incremental service to existing assets or capturing additional volumes on existing assets. So as you can see on this slide, and we listed those projects for your benefit in case you weren't -- didn't have your pencil out, you weren't taking copious notes and along with your corresponding in-service dates on the left side. And then on the right side of the page, we do continue to believe that our organic spending is going to be $1.5 billion per year. As you'll probably see in the dark blue shaded area, we've got about $1.4 billion of approved projects for 2022. So that doesn't mean that our commercial group is taking the rest of the year off. You heard Jim during the last Q&A session talk about the potential for a natural gas takeaway solution out of the Permian. You heard Angie and Carrie talk about what they're working on with respect to carbon capture. And Brent mentioned that we still feel strongly about our spot projects. So to the extent we get some of those projects across the finish line, there is some incremental room for CapEx to grow above $1.5 billion for 2022, but we do think it will stay within a $1.5 billion to $2 billion band. We introduced this next slide last year. But given the focus on capital allocation, I thought it was worth repeating. Enterprise has a 23-year track record of growing its distributions. And over that time, we've returned $43 billion to our equity investors. And to put that number into context, we ended last year with a net PP&E of $42 billion. And then as noted in the call-outs, our general partner has repeatedly and for no economic value, taken proactive measures to help the partnership's ability to increase its distribution coverage and its total payout. And as Randy mentioned earlier, there were 275 midstream companies that had distribution cuts. Enterprise wasn't one of those. Daniel and I put this slide together at the end of last year because as he mentioned earlier, we saw a lot of swing with respect to changes in working capital accounts and its impact on cash flow from operations. And as -- it was mentioned earlier, and when crude prices went negative in the spring of 2020, we were very bullish commodities. We layered on a lot of contango positions. And as those contango positions rolled off in 2020-'21, the $8.5 billion of cash flow from operations that we recognized included a $1.4 billion benefit from these changes in working capital. So what we wanted to do here with the 84% free cash flow payout ratio was simply adjust the denominator in that equation to eliminate the noise associated with those changes in working capital. We feel like this is a more accurate way and a more accurate representation of the amount of cash flow being returned to our investors.

And as Chris provided us with the amount of capital returned to Enterprise unitholders historically through 2021, it's noteworthy that 45% of our units are owned by individuals and trusts, 23% are owned by partnerships and corporations, and 32% by EPCO & its affiliates. If you exclude the investment by EPCO & affiliates, 66% of our units are run by individuals and trusts. And this data is as of the year-end 2020. So we think it's even higher with some of the return of individual investors over the past year. With respect to the term of the investment, 75% of our units have been held longer than 1 year, and nearly 50% have been held longer than 5 years. And I think these profiles drive what Brent referred to earlier as our long-term owner mentality. This mentality recognizes the fact that EPD is not merely a means to capture an occasional arm. It's really intended to be and managed to be a good long-term investment.

And I thought I'd finish out this section with just a real quick reminder on our thoughts around our financial objectives, which are also very similar to how we think about capital allocation. Enterprise is going to continue to prudently invest in the growth of its underlying business. We're going to grow our distributions to our equity owners. We're going to execute buybacks, and we're going to do all this while maintaining a strong balance sheet and financial flexibility. And as you may have noticed, there are no numbers on this slide because we're absolutely focused on all of the above. And with that, we'll ask Jim and Randy to come back up for any closing remarks, and we'll go to Q&A.

Okay. Hello. All right. We're going to have another opportunity to ask questions. No. We're bumped to balls up with us.

Michael Blum, Wells Fargo. Maybe just to go back to your -- the first set of slides that you went through, Jim and Randy, you talked about the decline in labor in the energy business. And I'm wondering if you could just speak a little more to the challenge. I think that's a broad issue in the country. But how the industry and you specifically what you're doing to sort of combat what seems like potentially a big issue down the line if you can't find enough good talented people to work at Enterprise and the rest of the industry?

Michael, I think first one, what we have seen, I guess, from a retention standpoint with employees, we've really held high retention rates throughout. And frankly, the response from our employees through the whole COVID situation, I think if anything, has made the organization more cohesive. And would come in and don't like that for granted. Graham, I don't know if you've got anything to have?

No, I think that obviously [indiscernible] last night, and we certainly see that. But I think that we've also been able to attract very high-quality individuals, and we're seeing an ability to go out and hire and backfill and continue to maintain high quality, and I think the folks that will continue to sustain our culture for a long time. And it's built in and we continue to regenerate it. But I think that we've got a strong reputation in the industry and people. People want to come to workforce in many field areas because of our reputation for being a safe, safe operator. We talk a lot about safety, but it's real when we were able to attract people who want to come work in a safe environment. So I feel pretty good about our ability to continue to hire and sustain our workforce going forward.

Yes, Michael, 1 thing I'd add to it is during the whole downturn with the COVID, we continued to come in, and we didn't lay off anybody through that cycle. We continue to come in and provide incentive comp, continue to come in and provide -- we didn't cut. We maintained our 401(k) match throughout and our retiree contribution as well. So really tried to come in and take care of the employee base.

Great. I just had 1 other question on LNG, maybe this is for Tony, I don't know. But Tony, you talked about line of sight to 25 Bcf of export and possibility of getting to 35 where you say you need any permits and pipelines. I'm wondering, do you think that, that will happen? Will we get -- will the country accommodate from a policy and regulatory perspective, the pipes and permits we need to get to that number? And then a broader question is, is LNG export an area that Enterprise would consider investing in either buying into or investing in any way?

I mean all -- I want to hear the administration making commitments to allies around helping them with energy given what's going on. So there are a lot of commitments being made and if you're going to fulfill them, you're going to have to promote permits and give oil and gas [indiscernible]. That's all I can say. I see the commitments being made just like everyone else who made the commitment yesterday to India, for example. That's the reality. We'll see if we follow through with commitments to getting action items.

I think we're probably missing...

2 questions. One, I'm just curious, given the high level of inflation, how are you doing in being able to pass that along in terms of contracting on new assets? And then the other question, to Tony's point, where you've got this pretty bullish outlook in the next 5 years. I'm just wondering Enterprise historically has always had plenty of projects to do. I mean your capital spend is pretty modest. Are you guys looking at relaxing that a little bit, maybe increase in CapEx? Are you still looking at keeping it kind of in this $1.5 billion range.

Yes, I think I can take the first question about the inflation protection. We did an analysis several months ago, just to profile all of our contracts and agreements. And we went through and just looked for any type of escalation features that would offset this risk. And 90% of our contracts have some type of feature, whether it be CPI, PPI, FERC index, which is really an indirect PPI escalation feature. And then there are a couple that were fixed. Rates have increased, but that was pretty rare. So we feel pretty protected. I would say the one thing about the escalation feature is there's a little bit of a lag because it's on a look-back basis on how we escalate our rates, whereas inflation is almost immediate on the cost side. So that will catch up towards the end, but there would be a little bit of a temporary lag upfront.

John, on your second question, I think really, it's our customers and the markets that drive our level of capital expenditures. We don't set an artificial level and say let's go fill it up, but it's really what do we see out there from a customer need or if something what we see in the market with what we're talking about with the Transwestern project.

Theresa Chen from Barclays. I wanted to ask a follow-up related to Chris' comment about the 3 major projects that could bring upside to CapEx this year; spot, CCS and natural gas takeaway capacity. If you had to force rank those 3 from most to least likely to move forward this year, how would you do that? And specifically on CCS, for Angie and Carrie, what are the gating factors to bring that across the finishing line up? What is going to make the customers say go?

Okay, I was talking to...

CCS and incremental natural gas takeaway capacity out of the Permian?

I think the first one is the one we can do.

Your mic's not on. Yes.

I think 1 of the quick takeaways is you can probably ask each one of us up here, and you'll probably get a different answer of what the force ranking will be. But I'll let Jim turn in here.

Yes. I really like spot because I think it's a magnet for our pipelines. And I really, really like that project. In terms of the carbon capture, you may have missed what Carrie said. But with that close on a project. And I was hoping we could make the eighth announcement today. But what we're looking at when you hear these guys. And I see a lot of upside on that. But when you hear these guys talk about carbon capture and sequestration, our role is -- personally, I don't want anything to do with the 45Q. I want to -- am I off-base Carrie, okay. I just want to collect fees on pipelines. Let them -- and we -- I mean, we're going to make an announcement for a long on a deal with strategic partner, where we're going to transport into CO2. They're going to sequester it. So that one has -- it may have not the greatest return in terms of who we've got signed up, but the upside is absolutely unbelievable. And the other, yes, we'd love to do a takeaway out of the Permian. I got to be honest. We've tried another at other times. And so far, we haven't been able to make it work. This one may have legs because we're using some existing pipe. But -- so we'll see. Well, that one's -- we're not there yet. We're [indiscernible] Natalie and Brent. Get the hell out there and just start talking to people, let's get this done, but we're not there yet. Natalie? I want to go back to something that Michael asked about retaining employees. I tell you, we brought the [indiscernible] up here with us. We didn't lay off a single employee in our marine business. We didn't make a hell of a lot of money. But we told those guys, your measure, you got to make money, but your measure is utilization. Keep your utilization up, we wanted to keep these -- we did not want to lay off. And in fact, when our trucking business suffered, we kept paying guys even though they weren't in the cab of that truck now. It wasn't the same amount of money, but we kept paying them. We didn't lay off a single person during the downturn.

And if I may, I have a follow-up question for Brent and his team. I know you talked a lot about your ethylene export capability and the growth from here. Just curious in terms of the current significant supply chain bottlenecks on the polyethylene side out of the Gulf Coast. Is that creating a tailwind for your ethylene export business, just that incremental bid for the ethylene cargo to get out of the Gulf Coast? And how do you see that playing out over the course of this year?

Do you want to take it?

Sure. Yes, the supply chain issues or the shipping issues for polyethylene, it's definitely creating a bid in the tailwind. But long term, I mean the fundamentals that I talked about with higher energy costs in the rest of the world and our ethane advantage, there's incremental capacity coming online and the terminal will benefit as a result of that.

Randy Horwitz from Westwood Investors. Yes, it's kind of a high-level question. But just in looking at the return on invested capital from midstream or downstream projects, what's kind of the way to think about sort of the typical mix of the return on invested capital that's coming from minimum volume commitments or take-or-pay versus volume or upside versus sort of like a terminal value assumption? And how has that evolved over the last few years?

Yes, Randy, I would say that typically, we've kind of averaged between 85% and 90% fee-based. We broke that down a couple of years ago in the midst of the pandemic. And I would say probably about 50% of those fee-based contracts were long-term take-or-pay based. Last year, we ended, call it, with about 18% or -- of commodity exposure or outside spread earnings, so a little bit lower than that 85% historical level. But that's not necessarily a bad thing. That just means -- yes, that just means just is making a lot of money and seeing a lot of opportunities with respect to how our assets shape up and the options that they provide. And so that's where we're able to keep taking advantage of that. And that was one of the things that was also somewhat attractive about the Navitas acquisition is that it got us a little bit more commodity exposure at the wellhead. And so we're seeing the benefits of that now relative to where we were at the end of last year just from a commodity price perspective.

Yes. And I'll come in and we don't have the slide in this slide deck, but it's in our other larger investor decks that are out on the Internet. But I think one of the things that Enterprise's provided, we have it going back to 2005, but it's the consistency of return on capital. And we put it in terms of gross operating margin over invested capital. And really, the bandwidth there has been about 10% to 13% return on invested capital over the years. In years where we see low commodity prices, you're seeing more of a 10% return on capital when you come in and you see more robust commodity cycles, that's when you see it trend back up to about 13%.

Brian Reynolds from UBS. One question just to follow up on spot is just how should we think about the project as it relates to the ethane export project, the ethylene export project and the potential for further NGL exports further down the line. Does spot kind of open up incremental capacity? Or ultimately, does spot ultimately allow more exports to come from Morgan's Point?

Brian, would you mind repeating that?

Just basically, how does -- would the spot project help debottleneck further NGL exports as you pursue further petchem exports from Morgan's Point?

But in terms of like an optimization exercise and spot, I think there's benefits to EHT so that will increase more dock space potentially for LPGs. In terms of Morgan's Point, that's a stand-alone deal between ethane and ethylene, not crude oil.

Just 2 questions on the financing side. How do you think about interest rates going up, I guess that's the first part. And the second part, have you seen any change in terms of how the banks are thinking about the energy space? And if I could, and Jim doesn't cut me off, the other question is just at what point of time do you think the energy evolution team would make a meaningful contribution to the gross operating margin?

Okay. Do you want me to start.

Sure.

Yes, Yves, good question. And I want to say, really, we began 2021 and up, I don't think it was -- so I think it was the oil and gas industry in a very defensive posture when -- again, when you came in and looked at the administration and you looked at the rhetoric, as far as being anti-fossil fuels. And I think this -- and really, it was highlighted early on when you came in and just looked at the composition of the administration. And some of what they were looking to do was come in and there was actually talk. I think there were discussions held to try -- for regulators to put pressure on banks to come in and not lend money to the fossil fuel industry. I think you also heard that from certain institutional investors as well. So when we went into the year, we went in very defensively, very conservatively. That's somewhat when we kept getting the buyback questions last year. We were really scratching our heads because in a 5-year period, we went from an external financing model to an internal financing model. And at the same time, we're hearing an administration that wants to come in and "get rid of fossil fuels" and start them with a balance sheet and it was like doing large buybacks seemed frankly irrational because what we were looking to do is come in and fund our own growth and take care of our own house. So with that, we probably saw more impact on the European banks. I'll tell you what our bank groups have been chanced. They have to come in and continue to step up for us. We made it easier for them and that we came in and basically reduced our commitments from the banks. This is something we did, and I go back to [indiscernible]. You try to do win-win deals with your customers, but you also try to do win-win deals with your financial providers. So we tried to make the lift heavier or easier on the banks by coming in and reducing bank capacity by 25% over that period of time from $6 billion of commitments to $4.5 billion. What that drove us to was to come in and let's go to the debt capital markets a couple of more times which our debt providers have been chanced also. They have backed us so much and they backed us with long-term paper. And we've come in and extended the debt portfolio that whole theme of financing long-term assets with long-term capital, the average life of our debt portfolio was still 20 years. And I want to say before Navitas, we were probably 99.5% or 99% fixed rate. You come in post Navitas, we're probably still 95% fixed-rate debt. So we feel like we're in a good place. We have been preparing for an escalation in interest rates probably for 10 years. But we're not happy that it's here.

At what point is this...

Yes. We're in the early innings, Yves. We put this group together, I guess, a year ago, Angie?

Right.

And put a commercial component in it 9 months ago, Carrie? And so we're in the early innings. I think if we are able -- the most important deal you do is the first deal you do. And then I think there's a domino effect once you do that first deal. I think you've heard from Carrie and Angie, I mean this kind of thing fits us. I think we can build on it. When does it have -- I don't have a clue, but I think we got to [indiscernible] the team.

Jeremy Tonet, JPMorgan. Randa, I figure we don't often get the opportunity to hear from you. But I was wondering if you could share any updated thoughts from yourself as a Duncan's family perspective on the partnership or anything you want to share with us today?

I'll tell you what. She's going to kick my a** for dragging her into this.

Well, I think the fact that I am actively involved and I'm in the office every morning, between 7:30 and 8, and I leave between 5:30 and 7, speak to what the Duncan family's commitment to the partnership is. We obviously look on all our fellow unitholders as part of a bigger family. And I look at all the employees as part of a smaller family. So we're just committed to continuing to grow and have the partnership continued to be as successful as it has been in the past because I had some really big shoes to fill, and I intend to do it. Is that it? Thank you.

Keith Stanley, Wolfe Research. I think I heard this correctly earlier, [ Christiana ] say an ethane cracker could be built and you get your money back in 2 years these days with where pricing is. So I'm curious how the company is looking at the potential to be involved in building an ethane cracker and if there's any progress on getting commercial arrangements and long-term offtake type agreements to be able to do that.

Yes. Specifically, what I was saying is that a cracker built in The U.S. versus a cracker built in Asia can be paid for just on the energy savings and the feedstock advantage. I wasn't [ compliant ] we were building a cracker. But I'm sure if Jim were answering this question, he would say, if we can toll propane to propylene and butane to butylene, then we can do ethane to ethylene. That being said, it's not something that we're announcing or anything that we're close to today.

Okay. Any 1 last question before we -- okay. Thank you. Well, that concludes our presentation today and a couple of announcements before we break for lunch. And speaking of lunch it's going to be in that room behind us here. We're going to go out these doors over on this side, walk down the hall and it's going to be right behind us. And lunch is going to be served and it's ready for us. Secondly, if you valeted your car, Sheila has got little green tags back here for -- to put on your tag to paper valet. And thank you for joining us today. I think it was very good. I mean, it was really -- it's good to be here in person. All right. Very nice. Randy, any last words? Yes, that's right behind this. Okay. Well, then we'll go ahead and break for lunch.