Enterprise Products Partners L.P. ($EPD)

Thank you for standing by. Welcome to Enterprise Products Partners 2026 Fundamentals Update. [Operator Instructions] I would now like to hand the conference over to Joe Theriac, Vice President of Finance and Investor Relations. You may begin.

Thank you. Good afternoon, and welcome to the Enterprise Products Partners conference call to discuss the company's newly released annual supply appraisal forecast. The scope of the conference call will be limited to the supply appraisal forecast. Questions with respect to our current business outlook or financial results will be deferred to and addressed during our first quarter of 2026 earnings conference call on April 28. Our speaker today will be Corey Johnson, Senior Vice President, Fundamentals and Commodity Risk Assessment of Enterprise's General Partner. Other members of our senior management team are also in attendance for the call today. As a reminder, the information presented during this call represents the company's current views on certain key midstream energy supply and demand fundamentals and is qualified in all respects as forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are based on the current beliefs of the company as well as assumptions made by and information currently available to Enterprise's management team, including forecast information published by third parties. 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. And with that, I'll turn it over to Jim.

Yes. Thank you, Joe. We've got Corey Johnson here that, as Joe said, heads up our fundamentals group as well as our financial desk. And Corey has been around for a long time. He's been in virtually every business at Enterprise. And he's put a lot of work into this along with his fundamental thing. Corey?

All right. Thank you, Jim, and good afternoon, everybody, and thank you for joining us. Before we dive into the fundamentals presentation focusing on supply appraisal, I do want to touch on a few macro issues and start out with looking at U.S. production. So when we look at U.S. production in 2025, we saw that the producer was very disciplined. We expect that to continue into 2026. In addition to that, we expect the Permian Basin to be responsible for 85% of the liquid hydrocarbon growth in the United States. This is slightly down from our forecast in 2025. All of this can be found on Page 3 fundamentals outlook. Now why are we at 85% and not 90% like we had the prior year? Well, we're actually seeing some growth in the offshore area, Gulf of Mexico, which is quite welcome to our Gulf of Mexico assets. I'm happy to see that production returning. Now moving on to global demand. Petrochemical remains the primary driver for global demand for liquid hydrocarbons. In addition to us seeing that demand continue on the petrochemical side, we expect to see those avenues become brighter as we look at the destocking as a result of the Iranian conflict creating tailwinds not only for U.S. crackers, but crackers abroad that are being supplied by U.S. producers. Low-cost feedstocks provide advantages for the U.S. petrochemical industry and also those over in Asia and in Europe. And when we look at OPEC, OPEC typically provides market stability. In this particular case, as a result of the closure of the Strait of Hormuz, it's actually created quite a concern. A lot of the spare capacity that everybody has been talking about is capacity that you find on the wrong side of the Strait. So it was not there to help when needed. What actually ended up helping was the unexpected Russian barrels that have been sitting on the water for many, many months. OPEC production in the month of March was off by approximately 8 million barrels per day, producing around 20.8 million barrels a day of black oil. If we add in refined products and also petrochemicals and NGLs, that number is closer to 15 million barrels per day, quite the impact on the overall industry. As we look at natural gas demand, we expect that demand to continue to be strong, driven by not only LNG, but also by AI and data centers across the United States. Now we're not too worried about natural gas prices at this time because we see U.S. production continuing to be strong and keeping our Henry Hub price below $2.70 as we see it today. Do we see slight upside to this value? Absolutely, but we do expect it to be a cost advantage feedstock as well. Moving to the next page, Slide 4. As I mentioned before, the U.S. producer will remain disciplined. That is our expectation, and that's what we've been seeing in the market. If you look at the chart before you, from 2023 to 2024, you can see that crude prices range somewhere between $70 and $80. During that time period, producers produced somewhere around 300,000 barrels per day growth year-over-year-over-year. We expect to see that trend continue. There's no reason why we would see them step out. As you can see, the forward curve gives us a price of somewhere between $65 and $75 when we run out to 2029. Now today, we do see some short-lived very high prices. In fact, if you look at this chart, which was constructed yesterday at around 9 in the morning, prices were about $102. Now we've seen those prices fall about $10 from there, and we're closer to $92 today. So quite a bit of volatility, which is not what producers want to see when looking deep into the future for long-term operations. Could we see a near-term change in operations, specifically cadence of drilling and fracking? Yes, but I think it's going to be limited to small privates. Integrated majors are likely to maintain the cadence that they have and continue to produce what they were expecting to produce before the conflict. Moving to Slide 5. EPD sees the U.S. production forecast for the Lower 48 states to be slightly changed from our previous forecast, but nothing too dramatic. If we look at our oil forecast, we see that the barrels produced are going to be right around 14.4 million barrels per day in 2030. This is a 900,000 barrel per day increase over where we expect to see barrels produced in 20 -- or where we saw barrels produced in 2025 at about 13.5 million barrels per day. When we look at our wet natural gas, we expect that to be up about 1.7 Bcf a day relative to our previous forecast at around 132.5 Bcf a day in 2030 with a starting point of 118.1 Bcf a day. Our NGLs are relatively unchanged. We're showing 9 million barrels per day in 2030. That's about 100,000 barrels less on the page that you see. But in reality, rounding brings it closer to 50,000 barrels a day. So very, very, very slight change in our NGL forecast with about 1 million barrels per day of growth from 2025. Now one thing that I did skip over, I want to set the stage on where we were on this forecast from a pricing perspective. We used $65 crude, $3.50 Henry Hub, and then we took where frac and rig counts were as of today, which is right around 480 rigs and 170 frac crews. And as we push down the time line to 2030, those crews would decrease through efficiencies. So we're pretty much taking where we see it today and trending. Let's turn to the next slide. So when we look at the Permian Basin, I brought this slide into the deck specifically for a reminder, a reminder of how truly prolific the Permian Basin is. When we look at the 2 maps on the top portion of the slide, it shows about 55 million surface acres. If we compare that to the likes of some other large basins, for example, in Appalachia, Marcellus, Utica, 55 million acres doesn't sound all that big. But when you think about what's underneath, it's very, very impressive. On the Delaware side, you have over 15 locations or drilling locations that you can hit, as you can see in the stacked pay cross-section at the bottom of the slide. And then if we look on to the right side of that cross-section, 10 different pay zones in the Midland Basin. So take that 55 million surface acres and on average, multiply that by somewhere around 13 different opportunities. It stacks up and it creates a lot of opportunity. Let's go to the next slide. So here's the real reason why I showed you the slide previously. It's all about locations. And so what we've done is an analysis looking at what total Permian locations look like in a $60 market. So if we look at that chart, it shows $60 with what we call a 25% rate of return. There are 80,000 locations in the Permian Basin at a $60 mark with a 25% rate of return. If I look a little bit deeper into that and break this down by producer, I can look at it and say, how many of my top 10 producers have locations at $60 with a 25% rate of return? Well, or how many locations do they have? Well, they have over 60,000 locations, bringing it to over 75% of the basin is controlled by 10 integrated producers -- or I shouldn't say integrated producers, but 10 producers. Now it's not just 80,000 locations in reality. It's 80,000 locations at $60. If I slide that scale to the left to the right, locations will increase and decrease. For example, if I were just to say, take that number to $70, 80,000 locations goes up to almost 110,000 locations. So the basin is prolific, and it continues to provide opportunities. As we've seen recently with Diamondback's statement saying that they have recently added 900 gross locations in the Barnett 500 net to their company as they expand into new areas. Going to the next slide. We're going to focus now on Permian production. As I mentioned before, 85% of the growth in the United States comes from the Permian. Similar to the overall 48 states, we run a bottom-up analysis, and we look at rigs, frac counts and what that cadence looks like. So starting out with rigs. Right now, we've got about 220 rigs in the basin and 78 frac crews operating. We expect those numbers to hold steady through 2026 and then start to slowly decline as we come out into the future. And again, this is a function of advanced technology and efficiencies. One thing that we've been really looking very carefully at with Permian production and looking at a lot of our metrics is it's not so much how many wells are drilled and how many of those drilled wells are completed. It's more about how many lateral feet. Now one well that we see today is not similar to the well that we saw 3 years ago. These wells have much longer laterals with much more complicated drilling where we see a lot of multi-bench completion and laterals that are no longer 1 to 2 miles, but more like 2 to 3 miles. So starting out with oil, where forecast for oil production in the basin is down about 100,000 barrels a day year-over-year at 7.5 million barrels per day. In 2025, our forecast was at 7.6 million barrels per day. Slight change to the down, but not a whole lot, still growing about 1 million barrels per day from a 2025 mark of 6.5 million barrels per day. If we look at wet natural gas, our wet natural gas is going to grow by about 6.7 Bcf a day to a total of 35.4 Bcf a day by 2030. This is up about 1.5 Bcf a day to our prior forecast. And then when we look at our NGLs, we expect to see 900,000 barrels per day of growth in 2030 from our 2025 mark at 3.8 million barrels per day. This is about 200,000 barrels per day over our previous forecast. Now one very important point that I'd like to address is what is the growth rate of not only our wet gas, but also our NGLs relative to crude. In 2025, that growth rate was about 1.4x. Now we see it growing at about 1.6x as we see the gas-to-oil ratio in the basin starting to increase or should I say, continuing to increase. Turning to the next page, Page 9. Permian Basin trends. So when we look at the stacked pays, they all continue to deliver. As I mentioned, they grow and they grow and they grow. We've had about 18,000 horizontal wells completed in 25 different named geologic zones over the last 3 years. When we look at what the producers are reaching out for, they're doing step-out drilling in places like the Barnett and the Woodford into these nontraditional benches. Today, we say that they're nontraditional, but they seem like they really are becoming more and more common every single day. A lot of that is driven by the fact that next-generation technology is making it a lot easier for producers to drill these locations as they see their economics looking better. Costs are coming down and total recoveries are going up. What's driving this? Spacing, cube drilling, lighter proppants. All of these things, again, are helping with total recoveries and costs. Not to mention, consolidation within the basin allows people to share technology and also create more efficiencies. Turning the page. So as I've mentioned before, 1.6x growth, wet gas and NGLs relative to crude oil versus what we saw in 2025, 1.4x growth. So obviously, that says gas-to-oil ratios are continuing to increase, and that's exactly what we see here. So I'm going to start with the top left-hand corner, the total Permian. The left-hand axis shows us what our gas-to-oil ratio is in Mcf per barrel. The right-hand side shows what our gas rate is on Mcf per day. That gas rate is a peak gas rate that we see at the early point of production. So for example, looking at 2017, peak gas rate was about 1,300 Mcf per day. The GOR at that exact moment in time was 1.91 GOR. As we move in time to 2025, the peak gas rate is about 1,900 Mcf per day and the GOR 2.24 for the total Permian. As you can see with the arrow, it's moving from the lower left to the upper right. Gas-to-oil ratios are, in fact, increasing upon peak production. We see the similar trend in Delaware, more pronounced in New Mexico and a little bit less pronounced, but absolutely there on the Texas side as well in the Delaware Basin. When we look at Midland, interestingly enough, we don't see that trend as pronounced, it's a little bit flatter. We do see a slight growth in that number, but nothing like what I would say our teams are seeing. So if we were to ask, for example, Natalie Gayden and her team who are out talking to producers all the time and Jay Bany and his teams, they would tell us what we're seeing in the basin is the gas-to-oil ratio in Midland look a lot stronger than that. So what do we have to do? We dug a little bit deeper. So let's take a deeper dive into that. Let's turn the page to Page 11. Looking at type curves is what gave us the answer. So year in and year out, the supply appraisal team nailed it on crude oil. We were always getting numbers exactly right on crude oil. And every single year, we were a little bit lagging on our wet gas and NGLs. I think everybody shared that same challenge. Well, we took that deeper dive when we looked at our type curves, and it's not about looking at what the type curve looks like today. It's about looking at what we think the type curve is going to look like tomorrow. And so when we projected out a trend of what those type curves will look like, the crude oil stayed relatively the same, but the natural gas type curves started to shallow. So the chart here in front of you shows a 2025 and a 2026 type curve for a typical natural gas well in the Permian Basin. The lower light blue line is what the '25 curve looks like and the darker red line above that shows the '26 curve. The shaded blue area represents the amount of wet gas production that comes from that well. Now we've calculated it for you. If we look at this type curve over an 18-month time period for 1 well, you would receive 100 Mcf per day additional relative to what we would say the 2025 type curve well would look like. That doesn't seem like a lot, but when you multiply that times 485 new wells per month for 18 months, that number starts to add up. In fact, it reaches 365 million cubic feet a day and about 48,500 barrels per day on average of incremental NGLs simply by shallowing that curve, quite the impact. Let's turn to the next slide. Many of you have seen this slide before. This is a simple visualization of what a barrel of energy looks like coming out of the Permian Basin. In 2022, for every barrel of crude, you get about 0.5 barrels of NGLs and 0.5 barrels of natural gas or 3 Mcf. When we look forward into the 2020 -- actually not look forward, but the 2025 barrel, as we see it, you get 1 barrel of crude oil, 0.66 barrels of NGLs and 0.64 barrels of natural gas or 3.78 Mcf. Now one point that I want to make about this slide, and it's a very important point to producers is what is the impact of negative gas pricing in the basin. So if we look at a, call it, negative $5 number that we see today in the Permian Basin, this calculates to about a $19 liability for every single barrel of crude oil that is produced. Now when we're looking at a $90 barrel of crude oil and we back out $19, it's pretty dongle on profitable regardless. But what does this really do? Well, if we turn the page to Slide 13, it makes the producer very excited about new pipeline capacity that is coming. Now here's where I'm trying to go on this, and I want you just to take your time and follow me. When I look at this chart and I look at the light blue line on it, that represents what we expect from a production perspective. So all the way in 2030, that light blue line reaches about 27.5 Bcf a day. That's the dry gas production that we're forecasting out of the Permian Basin. When I look at this slide, I immediately think, okay, where could we be wrong? And this is where we could be wrong, and it all depends on timing of these pipelines coming and if, in fact, the Permian to REX pipeline, which is the dotted non-FID, the pipeline that you see at the very end. Now if I operate these pipelines as we would expect or if we operate these pipelines as we would expect, 32 Bcf a day in reality is about 30 Bcf a day of true usable operational capacity giving up and downtime throughout the course of the year. So if we operate these pipelines at 30 Bcf a day, you've got a lot of producers finding ways to make natural gas disappear because they're sitting on, as I mentioned, that negative $5 gas, so they're doing anything and everything they can, whether it's going downhole, choking back some wells or even finding ways to create electricity wherever they possibly can. These are opportunities for natural gas to come back to the market when these pipelines arrive. So we could see about 2 to 2.5 Bcf a day fill these pipelines pretty quickly without a whole lot of crude growth because that production is already there. It's just curtailed. And what comes with 2.5 Bcf a day of gas is about 450,000 barrels a day of NGLs. So there's definitely some potential for upside, assuming that all these pipelines get built and the timing of which we are predicting. Let's turn to the next slide. Natural gas demand outlook. We definitely think it's strong enough to keep up with production. Global gas and power demand continue to drive the growth. LNG continues to be built out. Facilities continue to operate at higher rates than expected. Data centers continue to consume more and more power as we go on. In addition to that, when we look at global demand, we must remember that the European Union's long-term goal is to replace Russian gas, and there's no better place than the United States to supply that gas. As we look at data centers and we look at AI, continuous power is absolutely paramount. It is not something that can be toyed with. You cannot use power that comes and goes. It has to be constant. Not only does it have to be constant, but it also has to be reliable. And natural gas and coal are 2 very, very well-suited commodities to provide that resource. So we expect to see natural gas demand continue to be very strong on the back of not only data centers, AI centers, but also industrial demand because we've got a very, very cost-advantaged market relative to the rest of the world. When we look to the charts on the top right -- excuse me, the table on the top right-hand side, it shows what we think the low and high case is for growth. If we look at domestic growth, we expect it to be somewhere between 4 and 9 Bcf a day out to 2030. And then if we add in exports, which includes pipelines to Mexico and LNG, we expect that to increase by a further 7 to 17 Bcf a day. If we add it all up, we're right around 11 to 26 Bcf a day, low case, high case for natural gas growth in demand. Now if we take the middle, that's about 18 Bcf a day. I would lean to the higher side given what has happened in recent time with the Iran conflict. So I do definitely think that the opportunities for U.S. supply reliability, I think you're going to get a little bit more demand out of the United States. It's going to be stickier. Let's turn the page to Slide 15. Most of you have seen this slide many times before. It is a very simple slide. Every incremental barrel of energy produced in the United States must be exported. Starting out with crude oil today, we are exporting 4.5 million barrels per day. When we look at where we are going into the future, it's going to need to be about 5.5 million barrels per day. If we look at what's happening with ethane, it's almost 700,000 barrels per day as we speak, exported and that number is going to continue to grow. Natural gas, as I mentioned before, LNG is growing at a very quick pace. Today, we're at 20 Bcf a day, and it absolutely would not surprise me if we hit that 35 Bcf a day mark by 2030. And then finally, looking at LPGs, today, we're right around 2.3 million barrels per day with room to grow. Turning to Slide 16. World is definitely ready for our growth. The appetite for LNG continues to grow, and it continues to exceed everybody's expectations. Every year, people have their doubts, yet every year, we continue to see the growth, and we continue to see the barrels consumed. EPD expects that our LPG demand will remain strong with approximately 300,000 barrels per day of annual growth. Most of this is driven by heating demand and human needs. Jim likes to call this sticky demand. This is sticky demand in non-OECD nations that have a lot of room to grow. In addition to that, you continue to see petrochemical demand, especially given what's recently happened in the Middle East. The destocking of petrochemical feed -- sorry, the feedstocks, but the destocking of the polymers and then also the consumption of stored feedstocks is going to provide a long runway for a lot of demand to come into the future. We look at the bottom left chart, you can see post-shale revolution. On average, we've seen about a 3.4% rate of growth since 2012 to 2025. It shouldn't surprise you when you see 295,000 barrels per day of growth year-over-year. That's why we expect to see 300,000 barrels a day of growth year-over-year. That trend has been very strong, and we expect to see it continue. As Jim likes to say, price creates supply and price creates demand. Let's look at the next page, Slide 17. Originally, this slide was really just to focus on where the supply was coming from and where it was going to, the supply and the demand. As you can see, the United States represents about 47% of the supply today to the world. Asia, a very, very large consumer of that to the extent that it's 65% of the demand. Now here's the twist to this. This is pre-Iran conflict. This picture is. If I were to change this picture, you would see the Middle East supply section reduced by 1.2 million barrels per day. Most of that production goes to Asia. What is remaining is now about 400,000 barrels per day of production coming out of the Strait of Hormuz. Almost all of that comes from Iran. Other than 2 vessels, all of it has gone to China. The 2 vessels that didn't go to China went to India. Let's look at Slide 18. Why is everybody lining up for U.S. supplies? Why do they want U.S. light ends? It's very simple, price. If we look at the blue lines at the bottom, that represents your ethane, natural gas and U.S. propane. If we look at all of the red lines at top, that's what they're competing against. We obviously are in the catbird seat from a supply perspective when it comes to price. International markets will always reach for the U.S. barrel first. Let's go to the next slide. This one is quite simple. It's just a picture looking back in time to help put things into perspective. About a decade ago, the United States was exporting about 25% of the total waterborne market for LPGs. Today, we have reached almost 50% of the overall market. Most of this driven by residential market demand on the global market, but it also is being driven by a lot of growth in petrochemical demand as well. Very well diversified, and again, quite sticky demand. We expect that to continue. Turning to the last slide, Page 20. We are looking at ethane feedstocks and ethane exports. So when we look at ethane exports, similar to the slide before, but we're just looking at the United States because the United States is the only country that's exporting ethane. There are a few movements within the European Union, but nothing really to get excited about. Nearly 100% of the ethane that hits the water is from the United States. Now what this slide also shows us are the other molecules related to ethane that hit the water, ethylene and ethylene derivatives. If I add up all of these barrels and I put it in terms of total production in the United States, over 40% of the ethane that is produced in the United States is exported, whether it be as ethane, ethylene or pellets. Demand for U.S. petrochemicals, demand for U.S. NGLs, gas, crude oil continue to be strong, and we expect it to be a driver for the U.S. economy. Thank you. If you have any questions. Chris?

Thank you, Corey. Operator, we're ready to open the call for questions.

[Operator Instructions] Our first question comes from the line of John Mackay with Goldman Sachs.

Look, Corey, you touched on this briefly, but I'd love to hear a couple more thoughts from you on really how much of this outlook has changed given what's happened in the Middle East over the last 1.5 months. Said differently, if we'd ask you to kind of run the same thought process around fourth quarter earnings, let's say, what would the view have been at the time? And if I can push for it, I know we're not asking too many EPD-specific questions now. But given the context of the guide you put out there for 2027, what's kind of the macro backdrop that's framed up around that?

So I'm going to tackle your first question, then I'm going to let Chris give you the response for the second. When we look at what's happened recently, obviously, we're talking about the conflict in Iran. I really don't think our forecast because we're looking out to 2030 really has changed all that much. Again, if anything is going to change in the near term, this is going to be small privates that are trying to take advantage of momentum, not the big guys. In fact, and this is news just in not too long ago, but if you look at Diamondback's actions recently of, I think, Chris, what we said $800 million of debt that they retired in the market at what was 4% interest rate rather than putting that towards drilling, that right there tells me that pure capital discipline, and they're going to continue doing exactly what they said they were going to do. They're going to grow at a methodical rate and provide returns to their investors. Now where things could change, and it's not necessarily a part of our forecast, but it's definitely something that Enterprise pays attention to is NGL demand overall, and I say NGL because it's not just LPGs, it's ethane, it's propane, it's butane, it's naphtha. This demand is going to be stronger for longer, in my opinion, really because of the supply constraints that we have seen over the last, call it, 40, 50 days. And we're probably going to see some of those markets open up maybe in the next month or 2 months. If you can tell me, I'm excited to hear. But the longer this goes on, the longer that runway gets for people replenishing things that basically are consumed or destocked.

Yes. And John, this is Chris. I think with respect to your question about how this plays into our outlook for the remainder of 2026, our forecast for 2027, I think we'll address that certainly a great question, but we'll certainly address that as we -- in 2 weeks when we have our first quarter earnings call.

Our next question comes from the line of Theresa Chen with Barclays.

Corey, on your point about the 2.5 Bcf per day of gas currently curtailed or choked back given the lack of residue egress. As we get multiple egress expansions later this year, illustrated in your chart, how quickly would you expect this 2.5 Bcf per day of gas to come to market along with the 450,000 barrels per day of NGLs?

So thanks for the question, Theresa. And let me -- I want to reframe that real quickly. What I was mentioning about the 2 Bcf a day, that is incremental. So that was where we could be wrong. So what I was referring to is 27.5 Bcf a day is what we're forecasting in 2030. If we look at the pipeline capacity in 2030, we have non-FID right around 30 Bcf a day of takeaway capacity, about 32 Bcf a day, if you include FID 30 Bcf a day. And if you include the non-FID, you would have about 32 Bcf a day. So let's assume that Permian Direct gets built, which is that last one, that would give us about 30 Bcf a day of operating capacity in my opinion. Again, you've got nameplate capacity on the pipeline. You've got true operating capacity of all of these pipelines. And I'm obviously going to handicap it by a little bit. The 2.5 Bcf a day that I spoke of is basically the increase that we could potentially see of gas coming to market when these pipelines come on and the timing of which they come on as a result of gas that's truly being held back in the market today. So as our inventory continues to grow, crude oil or supplies continue to grow and the natural gas that gets held back continues to either maintain or grow, some of that gas that could fill these pipelines is gas that's just in waiting today. Does that make sense?

Yes. Thank you for clarifying.

And then yes, 450,000 barrels a day -- or should I say, 400,000 to 450,000 barrels per day of NGLs would come with that incremental. So our supply forecast, where we could be wrong, you could see that 27 Bcf a day go up by 200 -- 2.5 Bcf a day. And then again, our NGL forecast would also go up by about 450,000 barrels per day if all of this were to come to fruition. If you were to ask Natalie or ask Tug what they're seeing in the markets, I would definitely think that these pipelines could fill.

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

I want to go back to the question on U.S. LPG demand. I guess the question is, do you expect there's going to be any kind of fundamental shift in demand for U.S. LPGs in light of the Middle East conflict? And is that already reflected in your forecast? Or if not, is your expectation that once this conflict ends and the straight is open, do you think buyers kind of go back to their prior buying patterns?

I think it really kind of focuses around security of supply. And it's a great opportunity for people to get out and procure barrels with long-term contracts and secure supplies. Obviously, the U.S. market is a little bit sturdier than other locations.

Our next question comes from the line of Julien Dumoulin-Smith with Jefferies.

Maybe to follow up on that last question a little bit more. Can you talk about the ethane forecast? I mean obviously increased pretty meaningfully here as a function of higher NGL volumes. How are you thinking about the strategic opportunity at hand for you all in as much as implicitly, it seems to be a little bit more of an export opportunity. How do you think about tapping into that as you guys talk about that imbalance, to use the term here globally? How do you think about the various facets that you guys could pivot to it?

Obviously, we're continuing to expand our ethane export opportunities, and there's some growth that we do see in petrochemical complexes in the United States that's going to happen. So there's new demand coming domestically. And as we already mentioned, we've got some opportunities to export some ethane in the future beyond what we're doing today.

Fair enough. And I mean could you speak a little bit more to the technology and efficiency? You talked about this analysis underestimating some of the changes year-over-year here. What's driving some of that, if you can speak to that a little bit more fundamentally, right? And as much as the production outlook clearly seems to be trending in a certain direction here?

Yes. I think Exxon has spoken pretty extensively about the lighter proppant. If you look at Diamondback. They're very good at multi-bench completion with their acquisition of Endeavor. Endeavor was, in our opinion, one of the better drillers in the basin, and they picked up a very, very good operator and driller, which just only enhanced everything.

Our next question comes from the line of AJ O'Donnell with TPH.

I appreciate all the details. Just wanted to go back to maybe some of these nontraditional benches in the Permian that you've talked about producers stepping into. Curious, as you think about the infrastructure that's already in place or what needs to be in place, like how early are those conversations? Are we potentially going to see an acceleration there? Just curious how that all kind of plays into EPD's overall asset footprint.

Well, I think strategically, we're located pretty nicely when you look at Midland Basin and also into the Delaware Basin. Some of these step-out plays, well, we're still looking at type curves because they're very young, but it does appear that they're a little bit gassier than other type curves, which is going to play very nicely into the Enterprise book.

Okay. Just maybe one point of clarification there. I mean is that additional like investment that would be needed on EPD side to account for this growth? Or do you feel like you have the infrastructure in place there?

Yes, AJ, this is Chris. I think we've been adding additional processing plants in both sides of the basin year-over-year. And I don't think that, that trend is going to end anytime soon. As Corey alluded to in his production outlook that the basin has a lot of drilling locations left that are highly profitable. So we do think we'll continue to add and build new assets and grow alongside that production growth as our customers are asking us to build those facilities.

Our next question comes from the line of Brandon Bingham with Scotiabank.

Just wanted to go back to the type curves and the changes year-over-year. Just wanted to make sure I understood quickly that, that is more of a basin average change, not necessarily indicative of specific benches? And then just any thoughts on looking at this production uplift maybe in a different way, how many fewer wells would you say might be needed to reach these growth numbers at this point as a result of the flatter declines moving forward?

Well, that's a really technical question. I definitely need to get a calculator out for some of that. When we look at that type curve, yes, that's a generalist type curve for what we're seeing with newer production. So we're projecting these type curves to go forward into the future. Some of this is us looking at production that we see on our system and then also production that we see through other service providers as well where we're seeing that shallowing of the curve, and we continue to see it shallow more and more and more. So again, this is a projection into the future of what we think that type curve is going to look like. As it pertains to how many of these we're going to produce, I mean one of the challenges, if we look at it from a completion perspective or a well-by-well perspective, it's kind of difficult to use that calculation on a go-forward basis. Brandon, who heads up our supply appraisal team, what he's really trying to condition all of us to is looking more on a lateral foot basis rather than on a per well basis because these wells are changing pretty drastically relative to what we've seen in the past. So one well does not equal what -- a well in the past doesn't equal what one well equals today, especially when we're seeing wells that are reaching beyond 3 miles.

Our next question comes from the line of Jeremy Tonet with JPMorgan Securities.

Just wanted to compare, I guess, your expectations for LPG, NGL export versus existing capacity as you see it today on the Gulf Coast. Do you see sufficient capacity today with known expansions? Or do you think that the industry needs to expand further based on the growth trajectory as you outlined there?

Yes. This is Tug Hanley speaking. We believe there's sufficient export capacity currently available for quite some time.

And that's both ethane and LPGs? Is it similar for both?

Certainly, for LPG. Ethane, that remains to be seen.

Got it. And then I guess, same question on crude oil export side.

That's more of a function of freight, but there's certainly sufficient capacity to export the crude oil, but certain docks can export it more efficiently than others.

Got it. And just curious, I guess, with the imbalance in LPGs, as you outlined there, and just the gap in the market as it relates to display or Middle East LPGs that won't be supplied, do you think that the -- there could be sufficient, I guess, incentive to produce more in North America, be it in kind of other formations outside of the Permian where the economics might be dictated more by NGLs in a combo play than the Permian where it's almost associated NGLs, if you will?

I mean I guess you're relating to Argentina?

I was thinking the Mid-Con, but I guess you could go anywhere you want.

I mean I definitely think that the challenges we've seen in the Middle East provides an opportunity for not only the U.S. producer, but the midstreamer to capitalize on secure supply out of the United States.

But to your question on Mid-Con, what's the economics for a producer on what percent is oil-based?

I mean not a lot of it. I mean if you're going to -- it's all -- of it is oil-based. Right. So if I'm going to drill, I'm going to drill in Permian.

LPG is not driving the economics.

Not at all. It's crude oil.

Got it. Okay. I didn't know if it changed the balance of any combo play outside the Permian, but understood.

Our next question comes from the line of Sunil Sibal with Seaport Global.

I just wanted to clarify something on Slide 7, where you have the Permian remaining locations with the sensitivity to crude price. So on the right side chart is for top 10 operators. Is it fair to assume that those -- that's essentially all of them or most of them are in the public domain? And as a result, you're saying that about 80% to 85% of the producers will exhibit a certain kind of a characteristic with regard to how much of the -- how do they react to the commodity prices?

Yes. There may be 1 or 2 privates in there, but it's mostly publics in the top 10.

Okay. So then just to build on that. So I think you talked about how the producers have been fairly disciplined despite the increase in commodity prices. So what we should expect is that 15% to 20% of the production, which is in the hands of privates maybe exhibit more sensitivity to the commodity prices versus the remainder of the basin. Is that kind of a fair way to think about it?

Yes, you're reading the chart correctly.

Our next question comes from the line of Manav Gupta with UBS.

I just want to talk a little bit about the macro trend. I think globally, ethylene producers are realizing that the better way to make plastics is through the ethane feed. We're actually seeing some of the global capacity that was purely dependent on naphtha looking to close down even before the crisis started. So do you see this macro trend playing out and globally more ethylene crackers actually moving to a flex mode and basically going from naphtha towards ethane? And would that be a helpful tailwind for Enterprise in the future, basically, global naphtha cracking shifting more to ethane side?

Yes, this is Tug. We have seen a shift of naphtha crackers moving towards lighter feedstocks, specifically ethane. But generally speaking, it's also a good strong pull for our ethylene export facility as well.

Thank you. Ladies and gentlemen, I'm showing no further questions in the queue. I would now like to turn the call back over to Joe for closing remarks.

Thank you. That concludes our remarks for today. Thank you to everyone for your participation, and have a great day.

Ladies and gentlemen, that concludes today's conference call. You may now disconnect.