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

Good day, and thank you for standing by. Welcome to the Enterprise Products Partners 2024 Investor Update Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to Libby Strait, Senior Director of Investor Relations. Please go ahead.

Good morning. Welcome to the Enterprise Products Partners 2024 Investor Update Call. Our speakers today will be Co-Chief Executive Officers of Enterprise's General Partner, Jim Teague and Randy Fowler along with Tony Chovanec, Executive Vice President of Fundamentals. Other members of our senior management team are also in attendance for the call today. During this call, we will make forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team. Although management believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially from those in the forward-looking statements made during this call. With that, I will turn it over to Jim and Randy.

All right. Thank you, Libby. Good morning. On Slide 4, we have a listing of the topics that we're looking to cover today on this investor call. And with that, let me go ahead and hand it off to Jim kick it off.

We start every meeting at Enterprise with a safety moment. And I think it does a lot to help enhance our -- the culture of our company as it relates to safety. If you look at that slide and you look at our total recordable incident rates back in 2011 and did the same thing in 2010. We had a couple of events that we decided we had to really up the game on safety. So we brought in -- we took our most senior person in operations. His name was Terry Hurlburt, and we said, Terry, you've got an open checkbook to fix this. And it's the first time in my life that I've ever seen anybody exceed an open checkbook but Terry made a lot of progress on creating a safety culture at enterprise. And we've got Graham Bacon here. I'm going to let Graham go into what some of the things are that we did.

Thanks, Jim. This is Graham Bacon, Enterprise Chief Operating Officer. You can see from the slide that we have had great performance in reducing incidents over the last 12 years. Little bit of an uptick last year. But when we look at these statistics, what we're really looking for is keeping the events down that Jim referenced back in 2010, we didn't have any of those type of events, and that's really where our safety programs are driven. We really believe in strong leadership at enterprise throughout the organization, and we focus on leadership training throughout the year for our supervisory staff just to get that commitment. We believe that's the fundamental for a strong safety performance. We have our basic core, what we call our cardinal rules of safety that drive our performance and we hold our people accountable to that. Those are our true life saving rules that, again, drive our performance. I think one thing about enterprise when we compare ourselves to those rest of the industries, we have a strong technical support base for both our plants and our pipelines really lend to hand our operating staff, and we follow that up with a strong auditing process. That's going to continue to drive our safety performance and improve that safety performance we're never satisfied and continuing to drive down to a goal zero mentality on our incidents. And we believe that also transitions to reliability as well. I'll turn it back to you, Jim.

Okay. On the next slide, we pride ourselves on reliability. And on this slide, you can see, you take, for example, our gas processing plants that's 98% average online, but that unavailable includes planned and unplanned downtime. If we only just looked at unplanned downtimes, we're over 99%. And the NGL fractionation, I could easily say that should be 100% because I can't remember us ever force measuring supplier or a producer for lack of fractionation, we merely put the product -- the Y-grade in storage, get back the finished products and our marketing group, where's the difference? On our LPG export facilities, 98%, I guess where we have had struggled, Zach is when it's very, very cold or very, very hot. And what we've done and as a result of what we experienced last summer is we put in some processes to preclude the product before it goes into the refrigeration unit. On our propylene production facilities, we say 93% average on line rate. I think that overstates where we are -- if I looked at just the PDH plants, it would be more like 75%. And I think everyone knows, we've been -- we've had some challenges where our PDH plants are concerned. And we don't think that's acceptable. If you go to the next slide, Graham and I are going to piggyback this one. On PDH 1, we ended up having to do what no one does. We filed our engineer -- our E&C contractor halfway through construction. And that's just not done. We had -- we brought in another engineering and construction company have finished it. We were given -- essentially, we were given a [indiscernible] product and we've struggled with that ever since. Graham is going to go into what we're doing. But we're taking the turnaround right now on that plan, and we're going to spend some money we've identified all the issues that we think we have, and we're going to take care of them. On PDH 2, we've run Oleflex technology for 30 years. What happened on PDH 2 is in bringing that up. We brought it up just as we did our other Oleflex plants and then had an issue with Reactor 4, I think we have 4 reactors -- with Reactor 4, so we're running at about 75%, 80%. But at some point, we'll have to bring that plant down. But we feel like once we get that fixed, we've got a good plan. But Graham?

On PDH on, as Jim mentioned, we have a turnaround that's currently underway last in a couple of months where we're really taking the facility down to do quite a bit of work on cleaning out what we have a lot of heavies production that files equipment and one of the major efforts underway is to clean that equipment out. Also, it's this process is very heat intensive and very cyclic, and we have a number of failed components that we're replacing and repairing. In addition to that, as Jim mentioned, we had a lot of issues with the design and construction. We brought in additional engineering resources both in-house and as well as those that have expertise in this field to address the -- a lot of these issues that have caused reliability issues over the last several years. We're replacing catalysts, which will give us a lot more production and then also addressing a number of the major equipment items that have had some unplanned failures over the last several years. And I think at the end of this turnaround, we're optimistic that PDH 1 is going to turn from a headwind into a real tailwind for us that will address these items and have -- be successful going forward. On the PDH 2, just to add a little bit to what Jim said, this is kind of completely unrelated to PDH 1 and we feel like we had a really good project on PDH 2 executing throughout the pandemic. And at the end of the day, the plant was built to build robustly and would be reliable. We are having some issues that our licensor UOP is working to address issues that they haven't had, as Jim mentioned, we've operated these type of facilities for 30 years, have a lot of experience operating them. We found some issues that have come up with that have caused coking in one of the reactors. The licensor is working to resolve their procedures as well as some programming that would address various operating conditions that contribute to that. Unfortunately, we do have to take the plant down in the second half of this year to address existing issues, but believe once we get back up, again, PDH 2 will be a very robust plant for us. We turn over to the next slide 8, shows our emissions intensity through 2023 for the last 12 years. You can see the intensity per barrel the CO2 equivalent per barrel has gone down over that period of time in which we've invested over $51 billion in assets. We've had a slight uptick in actual emissions, but 3.3 million tons but given the amount of growth that we have, we believe that, that's been pretty dramatic in terms of the intensity. Also it should be noted at 25% of our total admissions are attributable to and owned by our producer customers and occur as a result of providing natural gas treating and processing services. When we look at the emissions reduction and most of this has been generated by transitioning from natural gas-fired equipment to electrical equipment in our facilities at Mont Belvieu as well as some of our processing facilities in the Permian. At this point, we believe we've done the majority of what we can do as low-hanging fruit in the other achievements are going to be much more expensive to get those levels down. In some cases, we haven't been able to do that just due to issues with the power availability, grid availability. And there may be a few minor opportunities, but by and large, we've accomplished quite a bit. And the new facilities will have a very low emissions intensity going forward.

Okay. On the next slide, one of the benefits of having a guy my age on the management team as you can look backwards and see what happened in the past. And I remember when -- and this was probably in the mid-2000s, when CMAI which now is a part of S&P Global. They said that the U.S. petrochemical industry in terms of ethylene production would shrink from 50 billion pounds to 35 billion pounds because we couldn't compete with Middle East crackers. Well, you can see what's happened as a result of shale on ethylene production. It has been like a tsunami and we've gone from my remember using 500,000 barrels a day as an industry of ethane was a big number. I think now you can -- when they're running at rates, they're using over 2.2 million barrels. So it's been quite a renaissance. What we found as we -- as our petrochemical guys recently went to AFPM and visited with companies from all over the world, there was a very high level of optimism. And you can see that when you look at what cracker margins are and you look at what polypropylene to polymer grade propylene is relative to polypropylene on the spread is we've seen it go from negative to double digits. So it's in the indication to me that you're seeing much more derivative demand. And I think a lot of this is about Randy, just the global GDP that we've seen. And I think even in Europe, there was a lot of optimism, and we see flows to Europe probably as a result of what's going on in the Red Sea and the Suez Canal more flow from the U.S. into Europe on petrochemicals.

All right. We've updated Slide 10 for the latest data from researchers at Oxford University on energy usage and global population data from the United Nations. This slide is a pragmatic reminder that the world has never done energy transition only Energy Edition. Global population is still expected to hit 10 billion people later this century and the demand for energy will continue to increase. It has been proven over and over, energy consumption per capita enhances the quality of life, both in terms of longer life spans and income per capita. That is why the world has added over half its population in just the last 50 years. In addition, most recently, demand growth forecast for electricity and expected capacity reserves are having to be rewritten due to the emerging demand for electricity to power data centers, support industrial electrification and even the proliferation of Bitcoin. As noted by Pulitzer Prize winner and Energy historian Daniel Yergin reality is stubborn, so were the laws of physics, thermodynamics and economics. We believe the world will continue to need all of the above in terms of energy supplies. The road to reduce emissions will take time and will be expensive. On Slide 11, this data is attributable to JPMorgan's 14th Annual Energy Paper by Michael Cembalest. This is a graph of installed power generation capacity in Germany. Cembalest's notes in the energy paper that in practice, only 10 to 15 megawatts of thermal fired generation can be disconnected for every 100 megawatts of wind and solar added due to the need to have dispatchable power supplies to back up intermittent wind and solar. The graph shows that despite Germany adding over 140 gigawatts of wind and solar capacity, has not meaningfully reduced thermal fire generation capacity, although it did retire almost 25 gigawatts of nuclear capacity, which approximate retirements of at 18% of new wind and solar capacity added. This results in higher energy costs due to the duplicative capital and operating costs to back up renewables. Per the European Commission in the EU, Germany had the fourth highest electricity prices for household consumers in the first half of 2023, over 40% higher than the EU average.

Okay. We're going to turn it over to Tony now on what our fundamentals group looks at. But just to kind of set Tony up I remember, and it wasn't that many years ago when the U.S. struggled to produce 5 million barrels a day of crude oil. I remember when the U.S. was producing 50 Bcf a day of natural gas and struggling to go into the winter with 3 Tcf (sic) [ Bcf ] in storage. I remember when the U.S. produced less than 3,500 barrels a day of natural gas liquids. And look -- and Tony is going to tell you where we are today.

Thank you, Jim. Starting on Slide 12. This is our updated forecast. And I guess what I'll say about them is they don't look a lot -- very much different than what they did last year. Probably no surprise. I think admittedly, when we published our forecast to 2030 last year, there was a lot of doubt maybe I would call some of it even pushback by all sides of the industry. But I think 2023 did a lot to convince people what the capability of the U.S. producer is and the services sector that supports them and largely what the Permian Basin is capable of. So I won't spend too much time on it. They look a lot alike. We did increase our case in point, we did increase our number of growth from '23 to '25 from 1.8 million barrels for the United States to 2 million barrels. Again, there's some tweaking that's going on in our forecast. But we're on a path when we look at what we had for rigs, for example, in completions, largely, that's where the industry is, and it is very Permian oriented. Moving to Slide 14 next. Maybe it's best to talk about the things that what we are watching outside of the forecast that looks a lot like last year. I guess, first and foremost, there's about a handful of them. First, we're watching the $133 billion plus of mergers that have recently been a been done or in the works. That's a large number. And we're wondering in the near term, does that change the cadence of production, I have to tell you, we spend a lot of time with the producer community, and we're not seeing it yet full steam ahead. So we'll continue to watch it, but we're not seeing any changes in that regard yet. In no particular order, the other thing that we're watching closely is what I'll call step-outs, particularly in the Permian Basin, probably the one that's most prominent that people are watching the closest is what I'd call the Barnett, Woodford. It does have the potential to be what I'd call a substantial and we're all in the process of learning about it. But it's one, there are others, but it's one that we're watching very closely. The third thing that we're watching closely is as producers have more contiguous acreage and just the scale of what the major producers are doing you're seeing what I'd call simultaneous drilling and completion. And think about -- some people call it co-development, number of words for it. But what think about a unit or you could call it a cube and thinking about looking at all the potential targets that you have, modeling and have simulations on all of them and drilling and completing them at one time. Obviously, you expose more rock that you might not have had you drilled them all separately. You have more production, better economics is what producers are after and last but not least, there probably there's going to be some upgrade to what the decline rates look like. So when I think about it and I think about potential game changers, just the ingenuity of the industry, certainly, this is one of them. The other thing that we're watching and we've put on this slide is the potential to increase the recoveries of the resource in place. So today, we look at that number as high single digits, I think, 8% to 10%. We put a quote on this slide as to what Darren Woods said about it when they acquired Pioneer. This is something that absolutely has the potential to be a game changer in the industry. And I'll remind you that things that happen in the drill bit in the field, moved pretty rapidly. So I talk about these things, I'd say they're largely not in our forecast, okay? And things that we don't know about from -- can't model from the 5,000 wells or so that are completed in the Permian every year. But any one of these and certainly taking all of these together we're looking at some things that take the industry probably to the next level as we go forward. I also think that I'll say a word about it, I think what people are missing now in the industry is the large proved developed producing wedge that we're growing. Early on with the shales, we talked a lot about the shale treadmill in the amount of wells that have to be drilled to grow production or even to keep it flat because you have these large declines. And I think people miss what happens as we build this base and largely with the shales that large decline turns into much shallower declines once you get between years 3 and years 4. And as you go forward, you just continue to build this large PDP base. I think if you want to look at the poster child in this regard, look to the Marcellus, we've been drilling the Marcellus heavily in the last 12-plus years. We put a quote on here what Paul Rady says, he's the Founder and CEO of Antero Resources. They've been in a maintenance mode. The Marcellus, Utica is producing about greater than 35 Bcf a day. And he says, we now plan to average these two drilling rigs and one completion group for the maintenance capital program that we have in 2024. Also contributing to our reduced capital is a lower decline rate. As we enter year 4 of our maintenance capital program, our decline rate is substantially lower in the mid- to low 20% range. This low decline rate requires less capital to hold production flat. Again, I would say that at enterprise, make no mistake about it, we model what that PDP wedge looks going forward, and we understand that it's building and what it means for decades to come for profitability for us and for the industry. Moving to demand, following up on some of the things that Jim and Randy said going to Slide 15. First and foremost, we absolutely believe that it's going to take all of the above source of energy to supply what we have coming. Yes, we have greater than 700 million people that gained access to clean cooking since 2010, that's a big number. But we're also reminded that about 1/3 of the world's population still lacks access to clean cooking and reliable energy. That's something greater than 2.5 billion people. We spend a lot of time, Todd, Brent and the whole team does in other countries. And I will tell you, the world has been on a trend. There's some noise in it when we look at all happened to COVID, but we've been on the trend to add something north of 1.2 million barrels a year of liquid hydrocarbon demand growth. You see forecast all over the map on this number going forward, but we're very comfortable with what we're seeing in demand to say that, that number will exceed 1 million barrels a year growth each year for the foreseeable future. And then last but not least, what we have on this slide, as we think about what's going on in the U.S. digital economy, again, you see some numbers that are they're actually hard to conceive, but you can't deny them. When we look at what's happening relative to data centers, bitcoin, artificial intelligence and just the amount of digital manpower that the United States and the lead that we have, it's not for the faint at hard. And I would say largely, as we go through the next few years, this is going to it's probably going to be lean on gas to supply this. Also, I note on this slide that in March of 2024, the IEA finally did step up. OPEC congratulated in the next day and said that the world needed an enduring focus on oil security as a consequence of the continued need for oil to fuel cars, trucks, ships and aircraft as well as to produce petrochemicals necessary to manufacture the countless number of items that we use every day. So that is the reality. And really that takes us to the next slide, and that's Slide #16. We show this slide continually, and we upgraded every year, and I'll just ask you to pay attention to the blue on the slide. If you look between 2010 and today, greater than 50% of the growth has been in naphtha's natural gas liquids and LPGs. And that demand is it's hard to see anything, but that wedge that blue wedge continuing to grow and now with ethane being a part of it. If you look at what China says, they call them their crude to chemicals, industrial parks, Reliance in India calls it oil to chemicals. And then if you think about what is happening relative to just ethane demand that Jim talked about, we see that that's the preponderance of what we've done in the petrochemical industry in the United States for the growth Jim talked about, and that is what we're seeing demand by the petrochemicals worldwide. They're looking to U.S. natural gas liquids for feedstocks because they've been so consistently profitable. Moving to Slide 17. This is a new slide this year, and it actually is one of my favorites. What we've done on this slide, think about that zero in the Midland and the blue lines above are what the U.S. has done from 2012 to today, for our change in oil and NGL production. It's pretty much up and to the right, straight growth up. Then on the below the line, so the gray kind of line, you see what OPEC+ has done to try to manage the markets in face of all that. So they have lost market share, okay? I think the other thing interesting, and I think as we go forward, something we need to pay attention to is OPEC now is scalping their supplies to try to balance the market. So it's not a straight line down. It's kind of a sculpt, and we hear them talk about that. As we see growth in GDP worldwide, and we see the population growth and the needs for clean energy that we've talked about, OPEC understands that there's going to be a point where they're going to continue to bring more barrels into the market. It's going to take what the U.S. can do and what OPEC+ can do. That's the reality. But for now, this is the picture. And I would go to the next slide, which is Slide 18. We've singled out LPG waterborne exports. And if you just look at what the U.S. has done from 2014 to today, so just the last 10 years. And then look at LNG, again, the U.S. has dominated taking all that market growth. LNG picture is going to change a lot over the next 2 years because we're going to bring another 10 to 11 Bcf a day of LNG onto the market. So I think that clearly, the U.S. has satisfied most of the global hydrocarbon liquid hydrocarbon demand growth over the last decade. Obviously, OPEC has had to concede market share to the United States. From time to time, they do bring barrels back and they will. The U.S. has been critical to development around the world in nations and was the growing, the lifeline that Europe needed after the Russian invasion of Ukraine, I think everybody should -- in this industry, we should be very proud of what they have done and what we're going to do going forward. That's my slide for today, Jim.

Okay. Thank you, Tony. This next slide, we never fail to put up a slide that shows our system. And one of the things that jumps out at me as I look at the statistics around the system. As we move today, 12.5 million barrels of crude oil equivalent through that pipeline system. I remember when we had 500 miles of pipe and 200,000 barrels a day of fractionation. Today, that system is 50,000 miles of pipe and it says 26 fractionators, that includes our refinery grade propylene splitters. From an NGL frac perspective, we have 2 million barrels a day of fractionation. I think with the announcement today, when we're through, we'll have 41 natural gas processing trains. And when we're through, we'll have 19 trains and the Permian Basin between the Delaware and Midland. And last but not least, we've got 20 deepwater docks that we export everything from ethylene to crude oil. And finally, it's not a small thing when you look at where at the pricing points for these commodities. From a crude oil perspective, we host the pricing point in Cushing. We are the pricing point in Midland. And with our new HOU contract that we have introduced with Magellan, we're more and more becoming the pricing point for crude oil on the Gulf Coast where the pricing point for NGLs and more and more LPG where the pricing point for sure, in all of the Atlantic Basin and more and more in Asia. And for ethylene and propylene, we've gone from a really robust system to a very robust system where we store it. We distributed and we export it and we are at the pricing point for those two commodities for sure in the Atlantic Basin. Whenever you look at hydrocarbons, it's always been, I believe, a supply-driven business, and I think it always will be a supply-driven business. There's 12 projects, if I count them right on this slide, 8 of those projects are supply projects, 4 of those projects are market projects. They are very much Permian focused at this point. But on our demand projects, they are exports, and they are one of the most exciting projects we have our TW -- our Texas Western product system where we just entered Phase I. And I think, Randy, you're going to finish up on this slide?

Yes. We've updated this slide to reflect the announcements that we made this morning that we completed Mentone 3 and the Leonidas natural gas processing plants in the Permian Basin. Again, we completed construction and they began operations. And then we also had the announcement on another natural gas processing plant in the Delaware side of the basin, the Mentone West 2 plant that we also announced this morning. With these announcements, we now have $6.5 billion of major organic growth projects under construction. Take a look at the bar chart on the right, the dark blue represents forecasted capital expenditures associated with the $6.5 billion of sanctioned projects under construction. The hatch blue part of the bar represents our current estimate of the potential upper range of capital expenditures associated with unsanctioned or unidentified projects. As you can see, growth capital expenditures for 2024 and 2025 are fairly robust with sanctioned projects under construction. Most of these projects go into service in 2024 or 2025, and we'll begin generating new sources of cash flow. In 2026, there is currently only $800 million of forecasted capital expenditures associated with projects under construction. That is why we believe even with additional natural gas processing plants needed to serve the Permian Basin or even yet another NGL fractionator in Mont Belvieu, our organic growth capital expenditure should normalize back to a $2 billion area beginning in 2026.

Just highlight a few of the projects that we have under construction. I know we get a lot of questions about our Bahia pipeline. But if you think about it, we are so tight right now. Shin Oak is full. We've recently put Seminole taking it out of crude service, put it back into NGL service when Bahia comes on, it will be pulled along with Shin Oak and that Seminole pipeline will be put back into crude service down below the Neches River NGL export facility. I have been very surprised at the appetite that we see globally for our ethane exports. We have 450,000 barrels a day of contracted ethane exports. And we see -- we have capacity for 550,000 whenever we get this finished. And we see a pathway to easily get that other 100,000 barrels a day contracted. So this ethane export facilities have become unbelievably successful, and it will be full. Our TW product system, we just did Phase I where we now are open at Hobbs and Jal. In April, we will open in Albuquerque and then midyear, we'll open at Grand Junction. We're already seeing a lot of activity in this. And oddly enough, we're finding opportunities that we weren't aware of that we didn't have baked into our economics that will only enhance the return we get on the DW products pipeline. If you look on Slide 22, this is -- this reflects what our exports have been of total hydrocarbons. And in the first quarter of this year, we averaged 70 million barrels a month of exports. Everything from ethylene to crude oil. The key to this is having the supply position that enables you to have this level of exports. In saying that, we've recently put in place an initiative to reach 100 million barrels a month of liquid hydrocarbon exports. If you think about that goal, if you are to realize it, it dominoes upstream. So you have to understand and enhance and expand your supply acquisition in order to reach this. We firmly believe that every incremental barrel of production as in this country has to be exported. We've also are keenly aware that our bread and butter are domestic petrochemicals and refineries. And those we've baked into what we are required from our supply position and still we expect to get to 100 million barrels a month of exports. On this slide 23, I think we are I said earlier, this is a supply-driven business. So we put that first, and we're working hard at expanding our crude gathering on our natural gas gathering and processing and Y-grade pipelines and crude oil pipelines. But we're also providing solutions, as I said, to our chemical customers and our refining customers. And it's not an accident that comes right after supply. Then we are, as I said, expanding our hydrocarbon exports. Our ethylene and propylene system expansion, if I showed you a slide of what our ethylene system looked like in 2018. It would be a blank piece of paper. Both of these commodities now have a robust storage, distribution and export capability and we're seeing more and more product flow through our ethylene and propylene systems.

On Slide 24 shows our consistency in generating unlevered returns on invested capital for the last 20 years. This is a testament to our commercial and operating teams who manage our assets. In 2023, our unlevered return on invested capital was approximately 13%. This is in spite of the challenges we had at PDH 1 and 2, which resulted in less than a 2% return on approximately $4.5 billion of capital during the second half of '23. We believe as our issues are resolved, this headwind in 2023 will become a tailwind beginning in the second half of 2024. Moving on to Slide 25. One of our most important financial objectives is to consistently increase cash flow per unit over time. We believe this is the foundation to increasing the value and the worth of our partnership and thus, the value of our partnership units. Throughout business cycles, we've grown our cash flow per unit, which has supported enterprises consistently increasing the capital that we have returned to partners were going on 26 consecutive years. Very few midstream companies can say that. We believe, given the expectations for global and domestic GDP growth, demand for energy, continued production growth from the Permian and our organic growth projects currently under construction, we can continue to increase our EBITDA and cash flow per unit by mid-single-digit percentages over the next few years. Slide 26 illustrates how we have consistently and responsibly increased our cash distributions over time while maintaining financial flexibility to continue to fund our investments to grow the partnership. We are proud that we avoided the pitfalls of aggressive shortsighted financial strategies that struck most of our midstream peers that resulted in taxable transactions for their limited partners, forced C corp conversions and multiple rounds of distribution cuts. We have focused on building enterprise to prosper over the long term and to consistently return capital to our investors. We manage our cash flows and capital like we are owners because we are owners not short-term or unit management. Management and the Dunkin's family's 33% ownership is one of the defining characteristics of Enterprise. Since we completed our transition to self-funding, our equity needs through retained cash flow in 2020, we have annually returned between 55% and 60% of our adjusted cash flow from operations to investors through cash distributions and buybacks. We are comfortable with that range going forward in the near term. Should capital expenditures normalize in the $2 billion area, we have the flexibility to increase that payout percentage. Over time, we believe Slide 27 will become our report card. It shows how well we are increasing cash flow per unit to increase the long-term value of the partnership and how efficiently we are utilizing capital. Of note, we are the only large North American midstream company, those with market caps of $40 billion and more who have actually reduced shares or units outstanding since 2019 without material asset sales. With $40 million of buybacks completed in the first quarter of 2024, we have now utilized nearly $1 billion of our $2 billion buyback program. We achieved this while increasing our cash distributions for going on 26 consecutive years and continuing to make investments in our business. On Slide 28, you've seen this slide many times. We are an infrastructure company. We build long-term assets underwritten with long-term contracts and want to finance them with long-term fixed-rate debt to generate stable cash flow over the long haul. Our A- credit rating reflects our best in the midstream credit metrics, whether in terms of debt-to-adjusted EBITDA of 3x or adjusted EBITDA to interest coverage of 7.3x or average tenor of our debt at 19 years with all of that debt being on balance sheet and less than 5% of our debt being floating rate debt. Like I said-- like we said earlier, we managed our capital like we are owners because we are owners. We conclude with this Slide 29, which is a reminder of our financial objectives. These objectives are very similar to those at our IPO. We believe we have executed on these objectives successfully over the past 26 years, and we are excited about the future. Our return proposition to limited partners of a 10% to 15% total return has been fairly consistent over time. In our early years, it was more like a 5% yield with 10% distribution growth. During the financial crisis and the OPEC price wars, it was more like a 6% or 7% yield was 6% distribution growth. And today, as a mature midstream infrastructure company, providing essential services to producers and consumers of hydrocarbons, we believe our near-term total return prospects are in the 10% to 13% range, calling it a 6% or 7% yield with mid-single-digit percentages distribution growth, not to mention the benefits of buybacks over time. And with Jim, I'll turn that back over to you to conclude.

As I look at the future of our industry and our company, I couldn't be more excited about what the opportunities are. Our 40-something year old employees have a completely different exciting future than I had when I was 40-something and the industry I lived in compared to one day live in today. I've told Randy many times, and I even think I've told Randa I'd love to be 50 years old again, given what I see this industry is going to go now and what I see the opportunities are for enterprise. And I guess with that, do we hand it back to Libby?

Yes. With that, operator, we are ready to open up the call for questions from our participants.

[Operator Instructions] Our first question will come from the line of Tristan Richardson with Scotia Capital USA.

Appreciate the time today and really appreciate all the clarity and the deep dive on the PDH complex and your plan of attack there. I think when you aggregate planned and unplanned downtime in '23 versus what you guys see or expect in '24. How should we think about maybe aggregate downtime year-over-year or aggregate utilization year-over-year when we think about '24 versus '23?

You want to take? I mean where I am, is it going to be better.

Yes. We expect it to be better. expect real good uptime on our gas plants, fractionators, export facilities. And as we discussed earlier, we're expecting a big improvement in our propylene side, particularly on the 2 PDH units as we go into '24. We're expecting the work that we're doing on the PDH 1 and the turnaround activities, the work that we talked about on the reactors on PDH 2 is going to lead to a significantly improved uptime in 2024.

We focus. We laser focus on reliability. We understand what our role is in this business. Our role is to make sure the product flows from our producers. And we build in redundancy to ensure that, that happens.

Appreciate it. And then maybe just a follow-up. Jim, you talked about opportunities under development on Slide 23. Should we think of these as primarily organic opportunities? Or is this much more broad that could include organic and M&A? And then you also noted on that slide, crude pipelines and your crude business is front center. That seems to be maybe a little bit more emphasis than it's received in the past. Can you talk about maybe what's changing in the Permian such that you see crude as front center as a long-term opportunity?

Well, the fact that we see the need to put Seminole back in crude service once Bahia comes on line. But beyond that, I mean, we're not planning another crude pipeline yet. And -- but crude is going to be a big part. But it really -- as much as -- I can't tell you how many times we've tried to say, okay, we want NGLs to be less than 50% of our EBITDA our gross operating margin. And we keep getting the opportunities where we can get it below 50%. But crude is an area that we have -- I think we have a pretty good crude system. If you think about it, when we bought TEPCO, we had 3 little crude oil gathering systems -- is that right, Brent? And I remember, when we put the Eagle Ford pipeline in, I remember Dan telling me and there was EOG anchored that. But I remember Dan telling me, I don't care what you have to do you need to get that pipeline in. I remember when we did our first Permian pipeline, Brent and I had a dinner with Chevron. And we said -- and we threw out a number that other people weren't talking about and we said give us [ $150 ] and we'll build the pipe and that led to that pipeline. And then the Wink-to-Webster Pipeline, we really wanted to build our own, but I've got to admit this Wink-to-Webster pipeline that we own 450,000 barrels a day of capacity and has been really, really good. Brent, you got anything to add?

No, I think you covered it all. But I think on the growth opportunities, I mean, the biggest obvious growth opportunity on the crude oil side is going to be what happens with spot.

Our next question will come from the line of Michael Blum with Wells Fargo.

Can you hear me?

Loud and clear, Michael.

I wanted to stay on the M&A topic. I think Tony mentioned the build-out of data centers, likely a lot of natural gas demand in the U.S. down the pike over the next 5-plus years. Just wondering, I know in the past, you've had less focus on natural gas, among the different markets that you do own assets. And I'm wondering if your long-term active views on that market have changed at all? Does that make you rethink M&A on the natural gas side a little bit?

Michael, this is Jim. We focus a lot. If you look at it with 41 natural gas processing trains, I think that's our focus on natural gas. So if you're talking about long-haul gas transportation, Michael, we've tried in the past we were able to be successful on our Haynesville pipeline. It's sold out. But we've tried in the past to do long-haul pipelines out of the Permian down to the Gulf Coast. And frankly, we get better returns with liquid pipelines.

All right. Fair enough. And then I just want to add on slide -- I'm looking at Slide 26 with the distribution coverage ratio. And I guess, Randy, the question is, what is the optimal coverage ratio? Or do you have a level of retained cash flow after distributions you want to sort of target?

I think the zone that we've been in the last few years call it, that 1.7, 1.8 range. That gives us the flexibility to come in and we're retaining enough cash flow. And some of the way we look at this and the way we finance the growth CapEx is that retained cash flow as an equity substitute. Obviously, equity, the cost of equity capital is prohibitive. And so if you would, that's the way we fund the equity component of our growth CapEx. So I think that area in the near term, especially with what we have forecasted over the next 2 years, in '24 and '25 for the amount of organic CapEx, that seems like a reasonable coverage ratio.

Our next question will come from the line of Spiro Dounis with Citi.

Right. Maybe just sticking on that topic and talking about the payout ratio of 55% to 60%. I know you're not ready to provide a new one today, but maybe I'll walk us through the process of how you defining a new one. You just talked about the coverage on one side, and maybe that's one factor you look at. But as you go forward, you talked about CapEx kind of slowing down a little bit, normalizing. And with that, I assume maybe growth kind of slows to normalize too. So to the extent that's the case, does that sort of push you more into the buyback camp as opposed to distribution growth that maybe you don't want to into that coverage too much?

Spiro, we could. I think one thing I'd look back over -- if you just go back over the last 2 or 3 years, really, we got into a lower payout ratio, higher coverage number, call it, back in 2022. And we had the opportunity to come in and acquire Navitas. And so we were able to come in and use some of that cash flow to help fund that acquisition. So I do think we'll come back in once you get out to 2026, again, if we stick with that $2 billion area number on organic growth CapEx, you'll see a lot more free cash flow and then some of it is going to be what are the acquisition opportunities at that point in time. And you could see it go for whether it's distributions or whether it's buybacks or if there's acquisition opportunity, it gives us a chance to buy some discrete assets for cash.

Got it. Understood. And then maybe going back to try and marry up a few of the topics you'll discuss today. You just talked about the $2 billion to $2.5 billion of CapEx starting in '26 plus. And so I'm curious, as you look at Tony's growth forecast going forward, and you sort of put those two together, does that $2 billion to $2.5 billion allow you to sort of maintain your market share and grow at that pace? Or are you actually trying to achieve more or gain more market share?

I think it -- at a minimum, we'll maintain our market share. Our objective is to grow our market share. And I think that allows us to do that.

Our next question will come from the line of Jeremy Tonet with JPMorgan.

Just wanted to touch on some of the comments that you put out there with regards to the forward outlook and the potential for, I guess, AFFO per share growth in the mid-single digits over the next few years here. And I just want to confirm, that includes the look at '24 with the PDH headwinds as described, that's still expectation to kind of hit that type of level or kind of a range over time that we should think about? Just looking for any more clarity, you might be able to provide on that.

Jeremy, I think it's -- I think we're feeling pretty good about 2024. But I would still come in and I said it on the fourth quarter call. I think the mid-single-digit growth is something that over time you can expect. I won't necessarily say it's going to be linear from 1 year to the next. But I think over the next 3 or 4 years, that's what we see. Now the one thing that we don't take into consideration from that is sort of picking up on one of Spiro's earlier questions, if we get the opportunity for acquisition growth, that's just going to enhance that EBITDA and cash flow per unit growth rate. But really, what we're talking about with that mid-single digits is really about what we have under construction and what we currently operate.

Got it. Maybe another way to ask the question just I think [ The Street ] has mid-single-digit EBITDA growth for 2024. And just curious, I guess, with regard to how you see the business, even with the headwinds that you described with PDH, is that level that you guys are comfortable with? Or any other thoughts that you could provide there?

I mean, Jeremy, I mean you guys are pretty smart. And it seems like that backdoor guidance is what you're looking for. But no, let's just say this, we're not uncomfortable with where consensus is.

Fair enough. I'll leave it there. And just a quick one, I guess, for Tony, with regards to egress in the Permian in thoughts, I guess, you talked about all this growth and just as far as incremental gas pipelines and oil pipelines. Wondering if you could talk to us about what you think the cadence is for -- is there a need for new greenfield oil pipe by the end of the decade? And how do you think, I guess, the cadence of new greenfield or incremental Natgas takeaway lines up over the balance of the decade, just for an industry point of view to make sure that production can hit those growth targets that the industry is capable of?

Yes. I think you hit the nail on the head, the industry is capable of adding pipes to support the Permian. I think our forecast only goes up to 2030, okay? But our analysis goes out much further than that. And I have to tell you, we see growth in the Permian growth at least another decade, okay. And I talked about the things that we're watching essentially, none of those are in our base forecast. Jim has a -- I don't think he said it today, but he -- he said the other day that he hasn't called the Permian Basin. He calls it the permanent basin, okay? But when we look at the PDP wedge, I guess, to answer your question, there will be more pipes built, and there will be pipes that will be combined and services will change, but the Permian Basin is a long way from being done. And I know just 3 years ago, people felt differently, but I think that's changing now. Anything to add to that from anybody else?

Our next question will come from the line of Keith Stanley with Wolfe Research.

A couple of follow-up questions on PDH. Any sense of how material the costs are for the repairs. And I assume that's all in the CapEx budget and not OpEx that would impact EBITDA and then any sense as well on roughly how long the PDH 2 outage might need to be in the back half of the year?

As far as PDH 1, the majority of that is either or it gets a lot of it on the catalyst side gets amortized over typically about a 4-year period. As far as the outage on PDH 2, still working up time frames, but you could probably consider roughly a month on that.

Okay. Great. The second, just a follow-up on M&A as part of the strategic outlook. Maybe you could first touch on some of the purchases of incremental interest in assets from Western and then how you're viewing consolidation opportunities going forward? I think, Randy, you alluded to timing being linked a little bit to having more excess free cash flow possibly in 2026. Just how you're thinking about it holistically?

This is Jim. In terms of what we did with Western is, frankly, we bought what we wanted, which was the fractionators and the Midland to ECHO 1 pipeline. I mean, that says it. Randy, do you want to take the other?

Yes. And Keith, and just your first question, one of the reasons you saw an uptick in our guidance on sustaining capital expenditures for 2024 reflects the turnarounds at PDH 1. On your other, I wouldn't say that the timing my earlier answer, the timing of an acquisition would have to made up in 2026. I think we take a look at the opportunities as they avail themselves. And our balance sheet and the [indiscernible] leverage that we run, we've got the flexibility to come in and go out and do a cash deal where it makes sense and whether it's attractive. So really the example of just getting out to 2026 was really, again, with the free cash flow there, we've got a lot of flexibility how we use that.

Our next question will come from the line of John Mackay with Goldman Sachs.

I wanted to go back to some of the forecasts from you, Tony. I know relatively small changes versus last year, but I guess, interesting to see you actually have -- you revised your U.S. forecast up a little bit more. It seems than the Permian -- so I'd just be curious to hear a little bit from your kind of your views kind of on ex-Permian growth and where that's coming from and whether there be opportunities for you guys?

Really, that was just to calibrate to what we saw actuals were there's -- and some of that was the Gulf of Mexico, which has some really lags in reporting, quite frankly. Relative to the cadence of the basins, we see it the same. We see the Eagle Ford very much steady state with a very large PDP wedge, again, that I think is unappreciated relative to the Bakken I think the industry has it about right on the Bakken relative to oil and then we understand what's happening with liquids there and appreciate it, it matters. But really, at the end of the day, and I've said it, it really is a Permian Basin game as we see it. And yes, we do project growth in the Permian past 2030, although we, at this point, don't forecast it. that's the reality. It's in and around the Permian. And I guess I'll go ahead and say it. I think given what we're seeing today, if I had to take the over or under on our Permian forecast to 2030 without a doubt, I would say that we're going to be low in what we're projecting. But it's a fool's game to try to go out too far and 2030 is still a long time. But even what the 3 or 4 things I talked about that really largely are not in our forecast. To say we feel great about the Permian Basin would be the understatement. But that's how we see the reality. And thanks for the question.

Yes. No, that makes a ton of sense. Maybe just shifting to the export target or goal, I guess. I mean if we think about spot, obviously, that could close the gap from $70 million to $100 million relatively straightforwardly, but what else could be in that wedge? And on a related point, you talked about how much of that is supply driven. How much more would you need to own or do or expand kind of on the upstream facing side to sell that $100 million a month target?

We're going to find out tomorrow in a meeting that I've got with our guys as to what that means and how we get there. I think it means more supply. I think also from a -- we are looking at that goal without spot, wood spot. Maybe it gets higher, certainly don't get lower. But we don't have a heck of a lot to do around our docks. I don't think Bob.

No, sir. I mean as far as the growth goes, it's going to be across all the commodities. We've got ethane expansions. We've got propane expansions, and we're looking at ways to handle the crude oil, whether it is with bot or without spot, we think the goal is achievable without spot.

Our question will come from the line of Neel Mitra with Bank of America.

Tony, you mentioned that an important piece to watch in the Delaware is the Woodford, Barnett formations, are you speaking to oil-based activity there? Or are you thinking about gas activity like the Alpine High just to understand that.

No, I'll -- let me clarify, really the place to watch it first is in the Midland Basin and more oil-related. But look, anytime we find oil in the Midland Basin and in the Delaware, you find a significant amount of rich gas. But I can't tell you that the industry can -- has a great road map to tell you what's going to happen in the Barnett, Woodford. But I think to think that it's not nothing, it's the long assumption at this point. We're going to learn a lot about that basin, we believe from our conversations with producers over the next 18 months. Hate to leave you hanging, but that's the reality.

Right. No, that's perfect. And then I just wanted to understand the $2 billion to $2.5 billion CapEx program in 2026 plus. Is there any general items that you can kind of detail there in terms of number of processing plants you want to build every year or how often you need to build a fractionator, is there some base CapEx that we can be modeling each year to understand what you need to maintain or grow?

Right. Neel, the -- if you've seen what we've done in the Permian, it seems like we've been needing to add to natural gas processing plants every year. And the prospects of further growth and more plants are out there. We just announced one this morning. That's where we come back in and again, I think we come back to sort of that $2 billion is a good run rate as we sit here today.

Neel, this is Jim. I remember when we brought on our fourth fractionator in Mont Belvieu. I kind of stood on the table and said, you know what, we're not -- this -- we're not building a fifth fractionator don't even come in my office and ask for it. And now we're sitting here with 2 million barrels a day of fractionation capacity. I guess, 13 fractionators in Mont Belvieu. And at the rate our guys are going, would surprise me to see frac 15 at some point.

And that's where we still think even with that, we still got room in that $2 billion go by number to fit that in.

That's all the time we have for questions today. I'd like to turn the call back to Libby Strait for closing remarks.

Thank you, everyone, for joining us today. That concludes our remarks. Have a good day.

This concludes today's conference call. Thank you for participating. You may now disconnect.