ONEOK Aktie

Good afternoon. We'll be kicking off our session. Welcome again to the 42nd Annual Strategic Decisions Conference. I am Bob Brackett, Co-Head of Energy and Transition here at Bernstein. We are not expecting a fire alarm or a fire drill. And so if the alarm rings, please take it seriously.

The first path of exit is out the back door to the right, all the way to the escalators that you came up down to the street and wait for further instructions. If for whatever reason that path is blocked, you go straight back. There's a series of internal stairwells that are well marked, take one of those down and follow the lighted path there.

Ultimately, this is your conversation. This is a fireside chat. There's [ floor ] up on stage, but there's more in the audience. And so ultimately, you should drive the conversation to do that, you will use either the website you've already pulled up, this pigeonhole.

If you need the QR code, there's a number of blue sheets of paper around the room that you can get that from. And what we'll do is I'll adjourn in one second. And we're going to follow a pyramid principle, which is we're going to start high. We're going to talk about the macro environment in which ONEOK operates, and then we're going to talk strategy, and then we're going to move down into assets and operations.

So that's how we'll progress until your sufficient questions come in. With that, it's my pleasure to introduce Pierce Norton, President and CEO; Walter Hulse, EVP, CFO; and Sheridan Swords, EVP, Chief Commercial Officer.

And we know where we're going to start. I was telling them we have the majority of S&P Energy here at this conference this week. Think about these folks, think about KMI and Exxon and Conoco and Chevron, majority of the energy S&P, but energy is only 4% of the S&P.

So over time, we hope to improve that number. The one thing that everyone is talking about in energy, of course, is the Strait of Hormuz. Like as we talked about ONEOK's business model, they're 90% insulated from something. Their fee-based, their revenue is locked in. Nonetheless, they are in the midst of it.

And so kind of asking you all, where are we in the Strait of Hormuz issue? And what has sort of surprised you about it? What are you sitting here not understanding fully today?

Well, I think I'd go back, Bob, before the war actually started. I think if any of us would have been told that you're going to shut off 20% of the oil supply and LNG supply and LPG supply in the world. What would the price do. I think we would all probably agree that it was almost going to reach an [indiscernible] type level and it did shoot up, but it quickly kind of came back down.

And I think as you unpack that, you kind of see why. You see the land storage, especially for the crude. You see the floating storage, you see the release of the strategic oil reserves. All of these things kind of help temper, I think, where the price is.

Now the longer and longer this war goes, then you're going to deplete those. And so it's going to be a matter of how long it happens and if it does, how quickly that comes back. The thing that I've kind of realized is that the most expensive energy in the world, the most costly energy in the world is the energy that does not show up. There's a reason why we need energy and it's used for stuff and it's used for the economy, it's used for society. And what's really expensive is when it doesn't show up.

When that shows up in poor GDP growth, it shows up in, frankly, a have and have not where a lot of the impact of this energy crisis is being felt in countries and places that we don't spend a lot of time thinking about. I think that's the case. How does it impact your business then?

Well, you just mentioned that we're 90% fee-based. So we're very insulated from these commodity swings. We do get a little bit of a tailwind for the gas and the commodities that we basically have unhedged.

We have a programmatic hedge in place that always hedges so far out. So we came into this year, especially in the first quarter, pretty much 75% hedged. So the impact on this is about the 25% that we don't. And like you said, about 10% of our earnings are really affected by this, but most of those are hedged. So really pretty little impact in the short term. Now in the long term, we do believe that there's going to be a shift of where people get their supply from. It was primarily based on price. What is the cheapest price. That's where people wanted to get their supply from.

I think this war has really woke us up the fact that something we probably already knew in the Ukraine and Russian war. I think Europe knew where they got most of their natural gas from. And I think the world pretty much knew where most of their oil and the LNG came from. But you shut those 2 things off and it really brings on where can we get reliable and resilient supply, not only price.

Yes, there is an argument in some of the Japanese LNG importers talk about diversity of supply and security of supply. And one of the things I think we learned is certainly countries like Pakistan and India, where they were getting a discount from their closest neighbor, some of the cheapest LNG on the planet, seemed to great to double down on the lowest cost molecule and now you realize actually a diversity of molecules across geopolitics and maybe even cost is the way to go.

What does that mean for you all? You're not going to deliver molecules to India, Pakistan. Does it change your thinking of those customers of yours that are thinking about the U.S. LNG export opportunity?

Well, I think as it relates -- I want to touch base on, we just might deliver some product. We're building an LPG...

LPG, but not LNG...

But the LNG piece of that is 18 Bcf a day is going offshore right now in the United States, quickly going to be building to 30 Bcf. There are some people out there that say that it's going to go to 36, 40, maybe even 50 Bcf a day.

Well, what most people don't realize is that 67% of all the natural gas that's produced in the United States comes with some form of liquids in it, whether or not that's considered a wet gas without the oil or an associated gas with the oil. So as that LNG grows and as that -- as the Permian Basin grows, the Bakken, the Mid-Continent and even the Haynesville and Appalachia, as those all grow, you're going to have quite a bit of liquids to take advantage of, and that's what we do. We're at a very diversified company when it comes to natural gas, natural gas liquids, refined products.

So we think that growth is going to really help spur kind of the next wave of basically midstream growth projects.

It's funny. Earlier on, we had [ Kinder ] make me happy talk about 26 Bcf a day of gas growth. And then we had Ryan Lance, the CEO of Conoco. I asked him, can Henry Hub ever get to 5? And he broke my heart and said, no, it's always going to be 350 plus, plus or minus, and we got plenty of it.

But to your point, when I build a longer-term U.S. gas model, you think about the drivers of LNG, think about data center demand and just power demand, like we love to add the data center to it. You are matching demand molecules against supply molecules. And in between, you shrink that wellhead wet gas massively.

And so if you don't actually account for the growth in U.S. NGLs, you actually don't quite get right the call on how much work the upstream has to do to pull that stuff out of the ground. And so talk to LNG every incremental gas molecule in the U.S. is an export molecule. Every barrel of oil is an export molecule. NGLs are now export molecules.

And it's funny you talk to Pakistan and India where LPG is front and center of how they think about their economy. What's the NGL export growth opportunity?

That's shared...

That's right. I think there's a great opportunity in LPG exports or NGL exports and LPG being propane and butane and NGLs will throw in the ethane molecule in there as well because people aren't -- first thing in the United States, people aren't drilling as we talked about, they're not drilling for NGLs.

It needs to be exported. It needs to go someplace into the world or else we can't get the gas and crude out of the system or out of the ground when that needs to be exported.

And today, domestic growth is -- we do not see any domestic growth in NGLs. So everything as well is going to go across the water. Obviously, we've seen that, that we've been very keen on that. We have a new export dock coming up in the first part of '28 that will export LPGs. We've seen increased exports of ethane, both Enterprise and ETC have brought on new export capacity for ethane, which also helps us because that pulls more of the ethane out of the natural gas stream that benefits our system.

So we have more throughput on our system on our NGL thing. So we think NGLs to be able to continue to help this growth in energy in the United States, continue to help grow the security of energy in the United States, plays a very important role.

And I think we're very well positioned for because we are in multiple basins when it comes to NGLs. We're in the Bakken, we're in the Rockies, with the Powder River in there. We're also in the Mid-Continent. We're in North Texas. We're in the Gulf. We're also in West Texas, each one of those areas. We pull from a great wide swath of part of the middle part of the United States, which actually gives us a tremendous amount of resiliency on our growth there. But the exports is where you're going to see the incremental molecule grow. And as we continue to grow, we think that there'll be opportunity, obviously, for our LPG dock that has expansion capabilities and maybe even beyond that.

And you can deliver certainly into Europe, you can deliver competitively into East Asia or can you deliver competitively anywhere?

I think you can obviously deliver competitively anywhere. There are some areas that want to pull more NGLs out of -- the Arabian Gulf has always been one of our biggest competitors on the LPG side.

Now you got the whole security side of it. On ethane, really, we're kind of the lone star on the ethane side of it, the one person that's doing that, almost all ethane to China is coming out of the United States today. And it's actually been a little bit of a political footwall in that area. But we deliver ethane into Europe. We deliver ethane into India. We deliver ethane into China. And on butane and propane, we deliver all over the world.

And there's -- it's kind of funny, I cover the mining side and almost all rare earth process metals come from China to the U.S., and they will use that as a tool. The converse is true with ethane, yes, the U.S. certainly doesn't -- the politicians of the U.S. don't use that as a tool.

Would you probably you endorse? How do you think about policy in today's world around hydrocarbons? Is there anything that the government should be doing due to the Strait of Hormuz or even due to sort of this vulcanization of world trade and tariffs?

So Bob, that question kind of opens up the door to regulation and how easy or uneasy it is to build assets in the United States to basically supply the services that are going to be needed because basically, you're taking these molecules from a place where they either have no value or very little value and you're transporting them to where they are or where they're actually needed.

So they're not necessarily consumed in all cases where they're produced. So our industry is not for deregulation. We are for modernization of the regulation. And what I mean by that is hardly anything that we do in life doesn't have some sort of time clock on it.

And so a lot of the regulatory processes don't. You've got to fulfill some requirement, but there's no real time as to when you have to do that. So the actual time that it takes to build these assets, even hundreds of miles of pipeline is extremely short in comparison to the regulatory process to make it happen. So I would like to see modernization of our regulatory process.

I know that the current administration is working on this. I know Secretary Bergland, Secretary Wright, they're doing a lot of work in this area. We now actually have a Senator from Oklahoma that probably knows more about the regulatory framework than anybody, Senator Armstrong.

So we're hopeful that, that's going to happen because you really do need some sort of legislative action that it just doesn't swing back and forth every 4 years or every 8 years because you need the certainty to make these investments because they are long-lived investments, they're 60, 80 years investments, and you really need some certainty to attract the capital that we need, and there's a lot of capital needed.

So drag-reducing agents in D.C.

There [indiscernible] for the legislation, yes.

The other set of assets you all have is on the refined product side. You've got bidirectional systems there. We've had tons of generals come in and learn words like tank bottoms and pipeline fill and folks, tourists and prisoners in the sector keep worrying about these things.

What can happen to the system where Strait of Hormuz stays closed, complexity keeps flowing through the system. Are there signposts where something breaks or gives? And what would that look like? And would you guys see it first?

Well, I think what you have to look for is it's very complex because you have to look for any sort of demand destruction. All the things that I listed before, like the floating storage, the inland storage, where are you going to get your gas from -- is the -- are the assets there to do that? I mean, if we build 40, 50 Bcf a day of LNG export capacity, is there enough import capacity around the world to do that.

So there's this combination of things that you've got to look at in the world. But I think it clearly points to a positive environment, I think, for the United States to be that security of supply for the world because we have that and I'm sure Ryan Lance would tell you this because I'm talking to them about it, but it's not that we don't have the supply. It's that we need to make sure we have the infrastructure to get it where it's needed.

Yes, I would argue, my analogy is to inflate a bicycle tire, you need a pump and to deflate a tire, you need a nail. And so when you look at the capital cost of a pump versus a nail, there are worlds apart. Liquefaction is maybe $1,000 a ton on a good day, if you're lucky and you got the right contract and [ gas ] is maybe $100 a ton. And so I'm always confident if the U.S. can build it, it will find a home, especially if it's competing in that home against thermal coal.

And thermal coal doesn't help you with intermittency, right? It doesn't solve that coupling with wind and solar. And so yes, my sense is get the U.S. infrastructure build, that's where the capital is, and that's where the bottlenecks have been.

Well, natural gas is really the only -- I call it the Swiss army of energy because primary oil production is used for transportation. Coal is used for electric generation. But natural gas, when you factor in the liquids and the natural gas, even the natural gas alone is used for generating electricity, you take it to the gas utilities, but then they turn around and take it to commercial customers, industrial customers or residential customers.

And strangely enough in the United States, almost 40% of all the energy that consumed for those 3 actually come from natural gas. So to try to replace it, I always argue that physics and economics win the battle just almost every time.

Pricing comes to play. Henry Hub price is fine, maybe at $3, maybe it goes up. Waha, Permian prices for gas are negative yet again. You're working to help solve that. What's the future of Waha pricing? Is it just boom bust like we've seen now for years? Or is there going to be a permanent transport linked price that solved?

Really I think you kind of go back to why is it -- why is the drill bit running in the Permian Basin, which is the Waha area, and that's basically on the oil price.

So yes, it started to come into play that, that negative pricing for natural gas is starting to make some of the producers act a little bit differently, kind of do some curtailments and those kind of things.

But it's really going to depend on supply and demand and how the pipes get built in between. Any time that, that gas comes on that fast, sometimes the midstream gets a little bit behind. There's a lot of projects in place. I think that's going to have capacity out there, but it's going to be definitely tight through the end of the year, it will relieve itself a little bit.

But if you look at the forward curve, it may kind of compress a little bit again in '27.

Yes. If you believe the forward curve, if you believe any forward curve, let alone if you believe one-off of a regional hub, fair point.

But then one solution is for you to go out and find customers and contract way too much pipe. The E&Ps, they wake up every day thinking about oil revenue. And then they think about -- right, they think about making money off oil and about moving gas, right, at almost any price. Can you get them to sign up like to solve the next problem? Or will it always be sort of start and stop?

I guess the way I'd answer that is you may not have to. And what I mean by that is throughout history as far as the large natural gas pipelines, it was usually the utilities decades ago, they needed the gas, that was the demand pull, they would take out the space.

And then they started to kind of realize that, hey, we got enough gas, got the supply in different areas, popping up. And then the producers kind of went into, okay, well, we're going to have to take the space out. What we're seeing is the combination of both. We're seeing the LNG companies and the facilities down in the Gulf Coast, they're reaching back to make sure they have that supply.

So they're actually taking some of that space out themselves. So then you got this combination of producers and basically the demand pull that's contracting the space.

And if we think about the backlog of projects that you all have that you're putting capital to work against, some are delivering to the coast. And certainly on the liquid side, right? Those are ultimately projects that go inland and you guys are dominantly start in the southern middle of the U.S. and go to the northern part of the middle of the U.S. and you're there. You're bringing stuff to the coast.

On the gas side, some of that's coming to the coast. There is latent demand for power demand across the U.S., not just on the coast. How do you serve that power demand client that wants that gas, whether it's for data center AI or whatever?

What I would say is especially we have natural gas assets, natural gas pipeline assets in the Permian. And predominantly here so far, that's all want to go to the coast, just as you said.

But we also have a way to deliver some of that up into the Mid-Continent as well. And we have a big Mid-Continent presence up there that also we are seeing that -- we're seeing data center demand up there. We're also seeing outright power demand as we go forward.

And Oklahoma does export overall export gas. We're seeing growing in drilling in some new formations, some old formations up there. So we definitely see gas production in Oklahoma continue to grow forward. So that way continue to be able to hit the pipelines that come into Oklahoma and feed the upper Midwest as well.

And we also have a gas pipeline in Louisiana, where that is the last mile pipe. We are seeing some LNG demand in Louisiana. But really along the River corridor, we're seeing a lot of industrial demand, whether it be a steel mills, whether it be ammonia facilities for fertilizer, or hydrogen facilities is coming in that area as well.

So as we think about outside of LNG, there still is other demand, some in the Midwest, but some in other areas as well.

Rank those. If we talk about LNG as demand drivers for your gas product, because LNG, data centers. I don't love AI, but there's data centers, AI data center, I'll say positively. And then there's reshoring. Ultimately, what you're talking about when you're talking ammonia, steel, hydrogen, that's kind of reshoring. Where do those, what's silver, gold, bronze...

Well, definitely right now, LNG is the goal because we're talking about we're at 15 to 16 Bcf, got another 15 to 16 Bcf coming online that's FID and going forward.

And that's day in, day out demand. I mean, then really, there's been a lot of hype around AI for sure. We think that's more in the 3 to 6 Bcf is really what it is.

And the funny thing about AI, even when you get on and they will contract on firm. So they'll pay no matter what. But the actual demand for gas is intermittent. Depending on how much people use it, computers and everything else, it's going to be up, it's going to be down, it's going to be going forward.

And so you probably -- because of that scale, 3 to 6 right now is probably you'd have to say, is the silver one but the other one is one that's coming up, as I said, steel mills, ammonia plants, hydrogen, that's really starting to come up a lot of Mississippi quarter, and that will be steady demand.

That will be all the time going forward. There's not going to be a whole lot of ratability. And as we continue to keep this gas price low as we've seen and more production come on, low prices are going to bring more of that demand in as well. And we're starting to see a little bit more of that pick up.

It's interesting. You kind of heard a theme about swinging around in volumes. I mean something that's not getting very much airtime is storage. And there's probably going to need to be more storage in the United States because things -- even these facilities, if it's demand all the time with the LNG facilities, those things go down for maintenance.

So where is that gas going to go? And I mean you got to one or two Bcf a day that's down instantly like that. I mean, it backs up in the system in a hurry. So there's going to need to be more storage.

I think it's more storage.

Yes. I mean go back to '23 or '24 when Freeport LNG had their explosion. We lost a [ B or 2 ] of export demand that destroyed Henry Hub, just backed it all up, took $1 or $2 out. What's interesting about those 3 demand drivers, LNG feed gas, the facilities run full.

Maybe there's some efficiencies and maybe it goes down a little bit over time for the same volume of export, but not much. Those are mature technologies. When you talk about steel, ammonia, right? Those are pretty well understood technologies, not a big learning curve.

The thing with AI is not only is that demand intermittent, that demand has the potential to get super efficient over time. We don't even know...

That's our answer. We don't know. The only thing is if you go back and look at history, when we come up with something that makes us more efficient, we end up in the future using more and more of it.

So overall, from an absolute demand doesn't go down, it can actually continue to pick up even though it becomes more and more efficient.

Yes. I'm going to ask a question and we got one from the audience. My question is I used to run strategic planning, and I always used to define strategy as tell me what you're not going to do. Don't tell me what you're going to do because that's relatively easy. What won't ONEOK do?

I hate to turn this around on Bob, but it's easier for me to tell you what we're not going to do, but tell you what we are going to do, which is we are focused in the midstream business. We're focused on basically that wellhead to the end user, to the demand pull.

Like I said, we move multi-molecules at the same time. That's going to be our focus in the midstream business. So you can take from that what we're not going to do.

And here's a question. I really like how it's framed. I'm new to ONEOK. Why should I invest into ONEOK on a 3-year investment horizon? And what are your top priorities or KPIs that drive the stock price materially higher?

I think Walt can probably answer this question the best because I think it plays into the amount of capacity we have for this growth.

Yes. I think we're in a very interesting situation here as we look forward to -- over the next 3 years. We've got operating leverage built into the system out of the Bakken, out of the Mid-Continent and out of the Permian, so that as volume develops in any one of those basins, we can capture it without any real significant capital expenditures.

So it's going to be very efficient from a capital standpoint going forward. As you look at the company, the why ONEOK, we've got an asset position in the middle of the country that is completely you can never replicate it.

It starts out in the Bakken at the Canadian border for NGLs down to the Mid-Continent, where you would then turn around and actually bring refined products back north or go south with the NGLs and the refined products. And in that middle swath between basically Colorado and Tennessee, we're the ones that have the asset position.

We can intermingle those pipes between NGLs and refined products to take availability of that capacity to drive demand. So it really comes down to at the end of the day, we're a rate times volume company. We've got a tailwind here as we go forward with commodity prices showing some strength. We're seeing modest pickup right now as people try to get their hands around where global demand is going to be.

But if this commodity environment stays, it's very supportive of good modest growth across our basins. And then you've got this LNG and AI demand that's going to drive gas and 67% of the gas that is utilized is coming as associated gas out of drilling for oil. We're going to be in a fantastic position to capture those NGLs.

So one KPI is your dividend, $2.5 billion that's a claim on your cash flow. Talk to the sanctity, and that's a significant dividend yield. Talk to the sanctity of that dividend and plans for it.

Sure. Well, we are one of the few midstream companies that didn't cut their dividend in 2020. So we have maybe a little bit more modest growth, but it's because we're starting at a much higher base, and we didn't cut it by 90% and then grew it back.

There were only three companies that did that -- I'm sorry, four. We bought one of them. So there are still only three out there that maintain that.

So I think that demonstrates the sanctity of the dividend. Our Board feels very strongly that they've committed to support that dividend. We talk about 3% to 4% growth rate in that dividend going forward. We've been at the higher end of that range. Our real focus there is to make sure that we can have a couple of percentage points of growth above our dividend rate so that we can always make sure that even in a down market that we can continue that dividend growth.

So you've got that call on cash flow. You've got some maintenance CapEx, that's the easiest CapEx to spend. And you're starting to approach an inflection on growth CapEx. And so you're going to start to see a free cash flow inflection.

Balance sheet is 4x net debt to EBITDA, which feels comfortable and we can talk to that. So at some point, you're going to have a high-quality problem of free cash flow. Is what I just laid out all makes sense? And if not correct me and then talk about this high-quality free cash flow problem.

You've captured it exactly right, mid-'27. We start to see our CapEx, the larger projects like the dock that we're building down in Texas City, those start to roll off.

And then you get into our kind of expand and extend our asset position, which tend to be the $200 million, $300 million, $500 million projects, which are significant because if you're doing it at 4x, they're giving you some meaningful EBITDA, but they're not the $1.4 billion or $1.5 billion that would put pressure on the balance sheet.

We can support that kind of growth, dedicate about $2.5 billion a year annually to CapEx and still have a significant amount of cash to delever. The rating agencies are perfectly happy like you are at 4x. We aren't getting any pressure from them. We think it's probably better to run the business closer to 3.5 or even down to 3x debt to EBITDA.

So as we see that free cash flow after we taking advantage of any real high-quality projects, we'll continue to see our balance sheet come down, support that dividend. And once we get that in place towards our leverage credit, then stock buybacks would be the last that would be there on the table.

One of the reasons you reduced that net debt to EBITDA for any industry is you're afraid. You're worried about the industry headwinds and whatnot. The other reason is you're opportunistic. We want to build a bit of a war chest or some balance sheet strength to do things. You guys have been acquisitive in the past and you've built out that footprint. What is the role that M&A plays for you all going forward?

Well, we definitely want to -- I won't call it a war chest, but we want to be in a position to take advantage of any opportunity that present itself. If we get down to 3x and we want to stay at the higher end 3.5x, that gives us $4 billion of cash that we can be opportunistic with.

There aren't really many opportunities that we're going to come across that are going to be in that range. In the space where we are now, we're in the $1 billion, $2 billion at one range or very large, and you wouldn't be in that position. So I think we want to be opportunistic. We're not worried about the business, but we do see the advantage of running at a lower level of financing so that over time, we don't bump up against 4x.

We bumped up against 4x here because of two very large acquisitions that we made. It repositions the company when necessary.

And you were able to do that and weathered it then. Question from investors. A lot of your competitors' peers seem to be diversifying into the wellhead. Why and how does your discipline to not do so pay off?

Well, I believe that's because we are large enough that we don't necessarily have to do that. And so I'm not exactly sure who you're talking about as far as diversifying in there on the midstream side.

What does Williams...

Well, I think Williams, kind of has really leaned into the natural gas side of the business. The reason we like the multi-molecule model is because at some point, does natural gas get saturated here in the United States. I know we're talking a lot about LNG. We're talking a lot about AI data centers and electric generation and those kind of in the industrial load.

But at some point, does that tail off. But the one thing I think you can say with the surety is that a lot of the natural gas is going to be used or the liquids are going to be used for decades and decades.

In fact, if you talk to the petchem guys and talk to the folks associated with American Chemistry Council, which is those people, they'll tell you that they really if you talk to anybody in the oil business or the gas business or any other commodity, they say, okay, out here in the future, something is going to hit and it's going to plateau and tail off.

I can't get anybody to tell me that the petchem industry is going to do that. I know you could have some pressure on plastics and these other kind of things, but there's just really no end in sight for that. And that's the reason we like the multi-molecule model for long term.

And I think that the investor base that we have likes that 90% fee times volume, stable cash flow that's coming in every time. Clearly, if we were to go towards the wellhead, we would be taking on meaningfully more commodity risk and variability into that stream. So we just don't think that's what investors -- if they want that, they can buy oil and gas.

You're putting steel in the ground will be there for the next generation to operate. If you're doing upstream CapEx, it's going to feel like handing sugar cubes to raccoons, right? And suddenly, you're like, what are we spending all this money on and you'd be on a treadmill.

So those multiples that those assets trade for are significantly less than ours. So...

Despite the fact that they take more risk, right? It's kind of a bit of a funny upside to report. So talk to and then we'll kind of shift now talking to operations.

We got through another winter in the Mid-Con. We got through winter storm Fern. At some point in my adult life, we started naming winter storms, which is a whole separate topic. But nonetheless, Fern came and went. Operationally, you guys were robust. What were the lessons -- what happened? What were the lessons learned?

I think even if you think about Fern, I think you may even want to go back to Uri a little bit, okay, where we were from that.

Because you think about it, then we had a lot of gas that went offline at that time. We had a lot of people worried about being able to get gas to their systems. We had a lot of failures that were happening up. You come to Fern other than that we did have gas go offline, but now we had a bunch of storage on there to be able to replace that gas as well.

We knew what systems we shouldn't shut power off to just conserve power because that's killing the gas going in. So I think you look at what happened during Fern as an industry, we did a lot better during that period of time. Now what we do know is that every year, we have winter. Every year, especially you talked about in the Bakken, some of our areas, we're going to lose some gas is going to be shut in for certain things.

And it's all kind of relative. If you are minus 50 in the Bakken, not a big issue. If you're 20 in the West Texas, that's an issue. And they're going to start because they're just not ready for that kind of thing. So we continue to put money into being our systems to be resilient as we have that.

During Fern, we didn't have any of our facilities go down. We lost some gas at the wellhead because some of the producers' facilities went down, but our facilities all were up and running during that period of time. And we want to continue to be able to be there for both sides of our customers, our supply customers, the E&P companies and also our downstream customers that are taking the energy we're delivering them and then delivering them to the end user.

So here's a way that we described that and what our people have embraced is that the assets that we put in the ground, Bob and the assets that we operate every single day, 24/7, that's our promise as a company to basically provide society with the energy that they need when they need it the most.

And when you're talking about Fern, Uri or whatever the name is going to be in the future, there will be more. That's what we're there for.

Interesting. You just said that there is value in having storage near the upstream. 20 minutes ago, you said there's a lot of value of having gas storage near the downstream LNG.

Talk to that specific investment opportunity. It seems it could be bite sized. What's the opportunity set? How do you go out and secure that storage? Is it geologically constrained? Is it permit constrained. Why not go whole hog? That's why we talked about this last year where that storage issue is out there. Is there something big?

Yes. We are actually expanding our storage facility. With the EnLink acquisition, there is a storage facility we have in Louisiana called Jefferson Island Storage.

And we are expanding that out to 10 Bcf from 2 Bcf going forward. We see some other opportunities in Louisiana to be able to do that. We see customers coming in on the storage. We just talked about utilities after Uri are much more interested in storage. The storage that we have in Texas and Oklahoma has all been 100% subscribed, and we've actually expanded that a couple of times and going forward.

In Louisiana, we're seeing much more from the LNG side of it coming in there as well. And they need it because if they go down, just what they said, they're buying a lot of gas, they need to be able to put that gas someplace when they have bubbles on their systems. And some of these industrial customers also need storage as well to be able to manage their exposure to natural gas prices.

So we see that opportunity. We got just going on. We're looking at other geological formations that we're close to or have already have some storage facilities to see if we can be able to expand that even more. But I think people are more -- there's a lot of projects out there looking for, looking at storage and there's different kinds of storage. You can have salt storage, which has a high in and out rate or you can have formational storage, which is -- you got to take it in and out a lot slower, but it can be a lot cheaper.

Depleted reservoir storage...

Depleted reservoir storage.

And so one you're looking to, it feels like it's an active market. And how do you sort of frame the economics of that, right? How long can that gas sit, right? How often do you have to cycle through storage for it to make sense?

A lot depends on how you contract it. Typically, the way you're going to contract a salt formation is you're going to have a pretty good rate for capacity and then you're going to charge for every return because if people come in there, they're going to want to turn that pretty quickly.

The formation storage is going to be a little bit more long term. You see more of the utilities come in, there could be a little bit more on an emergency situation and some of those. So it kind of depends on who your customers on stuff like that. If you can get a little bit of both, that's really good, and that's typically what you do. You get a little bit of both types of customers in each one of your storage facilities. We have both. We have both formation storage and salt storage.

And then coming back to data centers, you've disclosed up to or greater than a 5 Bcfd opportunity set around 40-plus counterparties looking at data center opportunities. Any color there, type of counterparty scale of the project, time lines of the project?

Well, I'd tell you a little bit, when we talk about 40, we're talking about hyperscalers and they're all trying to put something together to entice one of the big boys, the Meta, the Googles, the Amazons to come in and buy their products.

So really, when we actually get into there and you get through working with the hyperscalers, helping them out, your customer is really going to be an Amazon or a Meta or something like that. And not all 40 are going to go. They're all targeted.

And they're all coming in at different sizes. But we have of late, we first started seeing they started coming in, they were building them right next to the natural gas infrastructure because obviously, power was an issue to get in there. So we're going to build them near natural gas. We're going to build our own generation, and that's how we're going to get the power.

And they were putting it in areas where they were looking and they go, "Hey, we got a lot of gas pipelines here. We have some competition." But what we found out is they started off at maybe 100 million a day and then they go, well, maybe it can be bigger.

And the next thing you know if they're going, hey, can you give us -- instead of 100 million a day, can you give us 600 million a day? Well, that's a big difference in trying to deliverability into that. So all of a sudden, instead of being, hey, I got a 2- or 3-mile lateral, now I may need to be late 150 miles of pipeline to get back to where I can source that gas and have that capacity. So all of the project became much bigger.

So we're seeing that kind of going on, right, as we kind of go forward? Definitely because that's where our assets are. We're seeing Texas is a pretty hot bed right now, multiple locations in Texas. Oklahoma has quite a few as well that we're seeing going forward. And Texas seems to have more of an environment that people are looking to bring that industry in there.

And timing will depend on really how quickly they can access the generators for the power, whether or not be a recip engine or a turbine combined cycle, whatever it is, that's going to be -- we can lay the pipeline, we can get the supply contracts in place way sooner than they necessarily can get the equipment to generate the power.

Yes. There are customers that care about time, the customers that care about price, and there's customers that care about the quality of the product. We're a commodity business, so we can put that one to the side. And is it fair to say they are much more time sensitive than price sensitive, and therefore, they're good customers?

Absolutely. They're -- I mean it is -- speed to market is something we hear all the time from these guys.

Do they understand what you all do? Or does that even matter?

We've had to educate some. There's been some that have come in and said, "Hey, I want all this gas. Can you get that -- that's just -- you got a pipeline right there." Can we deliver off that pipeline? And will that pipeline moves 1/3 of what you're asking for.

You get some of that we've had. That's why we're going to have -- it's going to be a lot more than we thought it was going forward. So there is some education in there as we go forward. But the market is maturing a little bit. I'm getting understanding that more and more.

And but I think Pierce, is right, probably the bottleneck, the biggest bottleneck we see right now is getting the power generation secured.

You're about a year away from this cash flow inflection. To do that, you got to deliver on time, on budget, a number of projects. Give the audience some conviction that those are under control and what are the milestones to start turning on your key major projects over the next 12 months?

Well, we are -- here's a couple of projects we have. We have the Denver expansion supposed to be coming up in the third quarter. We're down to the end.

And it's looking good. We're going to be up on time to get to go forward. We have the Medford fractionator expansion, same thing. We're going to see the first phase come up at the end of this year, next phase coming forward.

Because we're -- where we're at in that cycle, very comfortable. All the assets are secured, the supply is secured. We just got construction to continue to go in there. We've got many milestones we're looking. Obviously, even we put the schedule out there, we had contingency for certain types of things.

Now as we look at that contingency budget on both cost and schedule, where we are at this time, extremely comfortable where we at. Getting into '27, we have a gas plant out in the Permian, 300 million a day gas plant coming online. it's earlier, but everything is pointing to that, that's on time. Supply issues have been an issue. We've been able to secure that some time ago, and it's rolling out as we continue to go forward.

So as we sit there, we track those with many KPIs. We have a whole teams doing that. We've been building long projects for an extended period of time for the last almost 20 years, we've been in a big organic growth mode during that period of time. So those -- as we talk about those big projects, we are very comfortable we will have them up on time.

One of the areas that people are starting to focus now on is compression. Because we have such a large footprint in 3 different basins, we've standardized our compression. We inventory compression 1.5 years, 2 years forward so that we can move those from basin to basin if we had to, we typically don't have to because we position in the right spot.

But compression will not get in our way from growth.

And the only thing I'd add to that, Bob, I mean we have done 5 acquisitions in 3 years. We've demonstrated the ability to bring in numerous synergies, find even more synergies than what we originally thought when we were buying these assets.

And the thing that I would say, some assets that you can buy, you're counting on a synergy that you've got to get somebody else to say yes to or a new contract or something like that to make it come to fruition. All of these synergies that we've done with our current contracts and current companies that we bought, that was within our control. That's important.

So when you have something in your control, then it's just a matter of focus and getting the right resources on it. We've done that. We're very confident, and you see it in our numbers.

There's synergies you control, synergies you don't control and then synergies you make up to make the acquisition price look attractive. Stick to the bottom line.

Let me say that, but I will say in these acquisitions, we've been surprised when we've gotten the teams together, the team that we bought and our legacy teams together and we get people down in the workforce really talking and understanding, we've probably found more synergies than we thought that was going to happen that came out, just bubbled up from beneath this, which has been very exciting to see that happen.

And that gets people excited. The next thing it keeps happening.

It's almost literally the definition of the word. Like we use the word to mean like we save money, but actually, the synergies like yes... make money.

We've got about a minute left. In that last minute, what ultimately is the value proposition for owning or buying ONEOK stock?

This is one of my favorite questions, Bob, because the value proposition is found in our assets and our people that run those assets, the ones that construct it, that build it, operate it.

And what that results into is where we have developed a multi-molecule fully integrated. I can't emphasize that enough, fully integrated set of assets that can bring tremendous amount of value all the way from where you move the molecule to where it's consumed.

That provides us with -- our target is the mid- to upper single digits on our EBITDA growth over the next 5 to 7 years. And it provides us an opportunity to increase our dividends. That is the value proposition for ONEOK.

Fantastic. With that, I thank you all, and I thank you in the audience.

Good morning, and welcome to ONEOK's First Quarter 2026 Earnings Conference Call. As a reminder, this call is being recorded. [Operator Instructions]

With that, it is my pleasure to turn the program over to Megan Patterson, Vice President, Investor Relations. You may now begin.

Thank you, Angela. Welcome to ONEOK's First Quarter 2026 Earnings Call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are available on our website. After our prepared remarks, management will be available to take your questions.

Statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer.

Thank you, Megan, and good morning, everyone, and thank you for joining us today. Joining me on the call are Walt Hulse, Chief Financial Officer; Randy Lentz, Chief Operating Officer; and Sheridan Swords, our Chief Commercial Officer. Yesterday, we reported first quarter earnings and raised our 2026 financial guidance, reflecting strong performance and building momentum.

Before we get into the quarter, I'd like to take a step back and frame the environment we're operating in and how we think about ONEOK's role within it. Energy markets remain dynamic, but long-term fundamentals are strong. It remains clear that the U.S. energy infrastructure is essential for economic growth, industrial competitiveness, power demand and global energy security. Midstream's role is simple: we connect supply and demand safely and efficiently across cycles, not around them. That's where ONEOK differentiates itself. We built a regionally diversified integrated platform at scale across natural gas liquids, natural gas, crude oil and refined products, anchored by an innovative employee base, the interconnectivity of our assets, customer relationships and a predominantly fee-based model.

Our systems sit in and around some of the most resilient basins and durable demand centers, including power generation, industrial demand and export markets. As we look to the remainder of 2026, our high-level priorities remain consistent. Operate safely and reliably, execute our capital growth program with discipline, maintain balance sheet strength and financial flexibility and leverage our integrated asset advantage and strong customer relationships to continue driving volume growth across all of our systems. These priorities are grounded in what we see across the U.S. energy landscape, where long-term demand remains constructive, both domestically and globally.

U.S. natural gas demand is growing across power generation for emerging data center demand, industrial activity and liquefied natural gas exports. LNG export capacity alone is projected to more than double over the next decade, reinforcing the durable global call on U.S. energy and natural gas infrastructure. 65% of U.S. natural gas production contains recoverable natural gas liquids. That means the infrastructure to handle natural gas liquids must be addressed alongside natural gas. This requires full value chain infrastructure and continued investments in natural gas, natural gas liquids, crude oil and refined product assets by companies like ONEOK.

At the same time, NGL demand remains strong globally, driven by petrochemical and international markets with U.S. supply playing an increasingly critical role. And finally, the resilience and innovation of the U.S. energy industry continues to stand out through consistent efficiency gains and reliable results. Recent global events have only reinforced the importance of secure, resilient energy supply and the critical role U.S. energy plays in providing it. The world has seen that the most expensive energy is the energy that does not show up. As global demand continues to grow, infrastructure, not supply, is the constraint. And that is exactly where ONEOK is positioned, providing scalable, strategically located infrastructure with capacity and the ability to respond to evolving demand dynamics.

I'll now turn the call over to Walt Hulse for our financial update.

Thank you, Pierce. As Pierce mentioned, we are increasing our 2026 financial guidance, reflecting the strong performance we delivered in the first quarter across ONEOK's integrated systems and our higher expectations for the remainder of the year. We now expect 2026 net income to increase to a midpoint of approximately $3.5 billion, with diluted earnings per share increasing to a midpoint of $5.53. We are also increasing our adjusted EBITDA guidance to a midpoint of $8.25 billion. These updates reflect strong underlying business segment performance as well as increased opportunities across our system, driven in part by a more constructive market environment that developed late in the first quarter. As we move into the back half of the year, the combination of higher volumes, completed projects and market tailwinds should be reflected more clearly in our results for the balance of this year and into 2027. Our total 2026 capital expenditure guidance remains unchanged at $2.7 billion to $3.2 billion.

Turning to the first quarter performance. ONEOK reported net income of $776 million or $1.23 per diluted share, a 12% increase compared with the first quarter of 2025. Results included a noncash impairment of $60 million or $0.07 per diluted share after tax related to our Powder Springs Logistics joint venture in the refined products and crude segment. Adjusted EBITDA for the quarter totaled approximately $2 billion, a 13% year-over-year increase, driven by higher volumes and strong segment level performance. As market conditions strengthened toward the end of the quarter, we also saw additional opportunities across our system.

We continue to expect the first quarter to be our lowest EBITDA quarter of the year, consistent with our typical annual cadence and seasonal dynamics. Importantly, our balance sheet and capital framework remains strong. We continue to prioritize financial flexibility while investing in the business and returning capital to shareholders. In April, we redeemed nearly $500 million of outstanding notes due July 2026. And we entered into a $1.2 billion term loan, further enhancing balance sheet flexibility in a rapidly changing market.

Our results reflect the same themes that underpin our strategy, a high-quality, largely fee-based earnings mix, strong performance across our integrated systems and disciplined cost and capital management. And our increased financial guidance reflects both this consistent execution year-to-date and improving market dynamics.

I'll turn it over to Randy for an operational and large capital projects update.

Thank you, Walt. From an operational standpoint, our focus remains on safe and reliable performance across our integrated assets. Our teams continue to execute well across all 4 business segments, managing normal seasonality and weather-related impacts. The scale and diversity of our systems allow us to absorb those seasonal dynamics while continuing to provide reliable service to our customers. Winter Storm Fern created temporary wellhead freeze-offs that briefly reduced throughput. But as a reminder, there were no material downtime on our assets on those -- related to those impacts were already reflected in our original 2026 guidance.

Turning to capital projects. We've made strong progress so far this year. In the first quarter, we completed the relocation of our 150 million cubic feet per day Shadowfax natural gas processing plant from North Texas to the Midland Basin. We expect a steady ramp-up of volumes as producer activity remains solid in the area. We're also on track to complete expansions of our Delaware Basin processing assets in the third quarter, increasing our capacity in the basin by 110 million cubic feet per day in addition to our 300 million cubic feet per day Bighorn processing plant that remains on schedule for completion in mid-2027.

In the Powder River Basin, we're on track to complete construction of our 60 million cubic feet per day in Cutter plant in the fourth quarter of 2026. This plant will increase our processing capacity in the Powder River to more than 100 million cubic feet per day. We expect capacity to fill quickly from wells already drilled and expected to be drilled by our 15% JV partnering plan.

Across other segments, our Denver area refined products pipeline expansion will add 35,000 barrels per day of capacity when it enters service midyear and Phase 1 of our Medford NGL fractionator will add 100,000 barrels per day of Mid-Continent fractionation capacity in the fourth quarter. These projects remain on schedule and are positioned to deliver meaningful near-term benefits by improving reliability, expanding connectivity and increasing optionality while also creating long-term durable value across our footprint.

I'll now turn it over to Sheridan for a commercial update.

Thank you, Randy. Commercially, we continue to see active engagement across our asset portfolio. Demand is supported by downstream pull, particularly from power generation, industrial and petrochemical demand and export-linked markets. These dynamics reinforce the importance of strategically located infrastructure and long-term relationships.

Looking at the first quarter, we delivered strong year-over-year volume performance across our assets despite typically seasonal headwinds. Starting with the Natural Gas Liquids segment. Performance was led by broad-based volume growth across all 3 of our core regions. In the Rocky Mountain region, NGL volumes increased a 11% year-over-year, driven by higher base volume and increased ethane recovery. In the Mid-Continent, volumes increased 4% year-over-year, driven entirely by C3+ volume, even as the region experienced some temporary impacts from Winter Storm Fern earlier in the quarter. In the Gulf Coast Permian region, volumes increased more than 30% year-over-year, primarily reflecting base volume growth from newly connected third-party plants that were delayed last year as well as higher short-term volume opportunity.

From a global perspective, NGL demand remains structurally strong and recent geopolitical dynamics have further reinforced the attractiveness of U.S. supply. Refreshed request for capacity on our announced LPG export dock were already increasing and have accelerated more recently as customers look to diversify supply toward the U.S.

Turning to the Refined Products and Crude segment. Year-over-year refined products volumes increased 12%, supported by strong gasoline and diesel demand, refinery maintenance dynamics, favorable regional basis differentials and wide crack spreads that drove strong refinery utilization. Blending volumes were also strong during the quarter. We entered the spring blending season significantly hedged, which limited our exposure to widening RBOB to butane spreads. Historically, wide basis differentials between New York Harbor, where we hedge and the Mid-Continent, where we sell product, also impacted realized margins.

Looking ahead, we've secured additional hedges on fall volumes at higher prices and extended new hedges into spring 2027. Importantly, blending volumes continue to be driven primarily by system throughput rather than EPA RVP waivers, which typically create only modest incremental opportunities. Increased gasoline throughput and completed synergy projects provide a much greater benefit, allowing us to optimize blending activity across our system.

More broadly, the reach and flexibility of our refined product systems remain a key advantage. We are the only refined products pipeline system with bidirectional access between the Mid-Continent and the Gulf Coast, which allows us to attract incremental volume and respond to changing market conditions. Demand fundamentals remain strong. We continue to see very strong diesel demand across our system, which we expect to remain as we move into spring agricultural season. We also anticipate a robust summer travel season, supported gasoline demand across our footprint. Additionally, if jet fuel supply remains constrained for an extended period, we could see incremental demand for gasoline.

Refined products and crude exports have increased in recent months amid global supply tightness, particularly related to diesel, and we are well positioned with dock capacity across multiple Gulf Coast marine facilities. Crude dock utilization remained robust at our highly contracted Seabrook joint venture, and we are in discussions to extend our contract expiring capacity at favorable rates. Finally, higher-margin Permian crude oil gathering volumes increased compared with the fourth quarter as activity in the basin remains favorable but disciplined.

Moving to the Natural Gathering and Processing segment. We delivered strong year-over-year volume growth, led by the Mid-Continent, where volumes increased 7%. Mid-Continent producers continue to focus activity across both gas-focused and liquid-rich plays, and we have 11 rigs currently operating across our more than 1 million dedicated acres in this region. In the Rocky Mountain region, processed volumes increased year-over-year even with winter weather and heater treater impacts. As operating conditions normalize, we expect volumes to strengthen in the second and third quarters. There are currently 11 rigs on our dedicated acreage with producers continuing to drive efficiency gains through longer laterals.

In the Permian Basin, processed volumes increased 4% year-over-year, and we currently have 11 rigs operating across our footprint. As Randy mentioned earlier, our expanded capacity in the Permian enhances system flexibility and positions us well to support producers' development plans across both the Midland and Delaware Basins. Customer activity remains strong, and we are increasingly encouraged by the depth of opportunities the Permian Basin brings to our portfolio. From a financial perspective, realized commodity prices were lower in the first quarter as a result of entering the year fully hedged. Importantly, underlying throughput volumes increased year-over-year across all regions, reinforcing the long-term earning capacity and resilience of our gathering and processing portfolio.

Producer behavior remains disciplined and execution focused. We are seeing some acceleration in completion activity, which supports our confidence in the 2026 volume outlook. That confidence is driven by direct visibility into producer plans rather than an expectation of higher commodity prices. This view is consistent with recent earnings commentary for oilfield services companies who have noted early signs of increasing activity, particularly among private and single-basin operators. DUC inventories can also provide an avenue for this acceleration. Our producer base across ONEOK's approximately 7 Bcf per day system is well balanced among large public companies, private operators and private equity-backed producers. That diversity provides both scale and durability while allowing activity to adjust incrementally.

I'll close with our Natural Gas Pipeline segment, where strong results continued in the first quarter with all regions outperforming expectations. Results benefited from wider-than-planned Waha to Katy location price differentials as well as incremental marketing opportunities created by Winter Storm Fern across our Louisiana assets. Looking ahead, we expect Waha to Katy differentials to normalize as new pipeline egress comes online in the second half of the year. Firm transportation demand remains strong with high contracted capacity and strong utilization across our system. We also continue to see significant interest from data center-related opportunities in Oklahoma and Texas, and we remain in advanced discussion with several counterparties. Additionally, LNG-related demand remains strong, both near term and long term, reinforcing the durability of demand of our natural gas pipeline assets.

Pierce, that concludes my remarks.

Thank you, Sheridan, Randy and Walt for those comments. To close, I'll come back to where I started. The energy landscape will continue to evolve, but the need for reliable, scalable U.S. energy infrastructure is not cyclical, it is driven by long-term demand fundamentals. ONEOK is built for this environment, having an integrated platform with capacity, a strong balance sheet and disciplined execution. The results, durable long-term value creation. Most importantly, none of this happens without our people. I want to thank our employees for their continued focus on safety, operational excellence, innovation and service. And thank you to our investors for your continued trust and support in ONEOK.

With that, operator, we're now ready to take questions.

[Operator Instructions] And our first question will come from Spiro Dounis with Citi.

Maybe to start with the improved outlook. Just looking for a little more granularity on how much of that $150 million move is maybe already realized here in the first quarter? And how much -- I guess, what level of visibility you have on the remaining forward component? Sheridan, you mentioned sort of hedging out butane through to '27. Just curious how much of that forward look is locked in.

Spiro, it's Walt. So first of all, I just want to clarify and make sure that it's clear that Winter Storm Fern was already in our guidance. So we have 0 impact from that as it related to the increase. The increase was really a blend of stronger volume expectations driven by higher commodity prices, continued expected differential opportunities. And then we, of course, expect to realize some benefit from the higher commodity prices, although we are hedged. Typically, we're hedged about 75% going into a year. But with the higher volume expectations, any volumes we receive going forward will enjoy the full benefit of these higher commodity prices.

Understood. Walt, second one maybe for you as well, just pivoting to capital allocation. So once again, you're trending a little bit stronger than expected. Could you just level set us on how you're thinking about the timing to sort of reach your leverage targets here? And when you do free up that cash flow, just where your heads on buybacks or any other uses of that free cash?

Sure. Well, nothing has really changed from our capital expenditure plan. As you know, and Randy mentioned, our projects are on time and right on budget. So we expect to start completing those this year with the Denver project finishing up and Medford first phase finishing up as well as some of the smaller things. As those wind down, as we've stated in the past, most of our CapEx will -- larger CapEx will be completed by midyear of 2027, and that's when we'll really see the free cash flow kicking in.

We're headed towards our leverage targets, clearly, with increased EBITDA expectations. As that denominator rises, we'll get there faster. But we continue to pay down debt, and we'll be in a position to meet our targets and return capital to shareholders appropriately. But I want to make sure that everybody understands our first objective is always to get high-return capital projects. So as we see those come in, we'll definitely try to prioritize those. But our expectation is free cash flow, there will be plenty for those, our dividend, our debt repayment as well as other forms of return to shareholders.

Our next question comes from Theresa Chen with Barclays.

Going back to your comments on the upstream outlook, though it's still early on, can you elaborate further on recent conversations with your producer customers? What are your near- and medium-term expectations for upstream activity in your areas of service? And where do you think prices will need to stabilize in the outer years to stimulate a material uptick in production? And how long would it take to see these volumes potentially materialize on your system?

Theresa, this is Sheridan. The first thing we're seeing with producers is what we call kind of leaning in to production. And that starts with -- the first one starts with is if there's anything that goes down, they are quickly getting that back up quicker than they do in a much more lower price environment. We also see them bringing on more completion crews. So that's kind of impacting your DUCs as they go forward or bringing things on quicker that they've already drilled. And the other thing, as I said in my remarks, we are starting to see some producers looking for additional rigs to bring online.

And as we see the environment that we are today, where a lot of people see the back end of the curve coming up, people are getting more excited about what the price environment is going to be going forward. Obviously, when we bring on rigs that the rig volume is a little more delayed into the back half of '26 than earlier. But as I said earlier, bringing more completion crews on and when they have any downtime getting that back on will be the more near-term effect on volumes.

And the second question is related to your export infrastructure and your outlook there. Given the call on U.S. energy resources and export infrastructure in particular, within your existing liquids export docks on the heels of recently building out the connectivity between Galena Park, East Houston and your Pasadena MVP joint venture, what kind of upside could you potentially harvest, whether it be optimization on utilization or [ incremental ] spot cargoes or even additional brownfield investment in Pasadena? And then on the LPG front, can you just talk through the commercialization process at this point? And have those conversations with potential counterparties accelerated?

Starting with our existing facilities, we have -- as you mentioned, we have 2 marine export facilities for refined products on the Houston Ship Channel, Galena Park and MVP. We have seen increased activity across those docks going forward. We still have more room that we could expand forward, and we are in conversations with customers around that. So there could be a little bit of upside in that area. On our crude dock, it is highly utilized right now. We have a lot more interest in there. What we're seeing is the opportunity to extend contracts or -- at more term, at more favorable rates than we historically have seen. So we see some tailwinds not only in '26, but beyond in both of our export facilities.

As it concerns our LPG dock, yes, we are seeing an acceleration of interest. We were sawing interest before the Middle East conflict, we're seeing even more of that interest. And right now, we are not concerned at all about finishing the contracting of our targeted utilization of that dock here in the relative near future.

Theresa, this is Pierce. I want to add something to what Sheridan said just to remind everybody on this call. Prior to the Iran war, the U.S. and the Middle East were the only ones -- only 2 countries that are actually going to expand LNG facilities over the next 5 years. And then if you fast forward to today and you look at the damage that was done to Qatar's LNG facilities, more than likely the equipment that was ordered to do those expansions will probably go to rebuilding some of the damage that was done during these war efforts. So that means that the incremental capacity is going to really land back in the United States. And with LNG going from 18 Bcf to 30 Bcf basically by 2030, I'd like to remind everybody, 65% plus of all the U.S. gas has recoverable NGLs with it. So that's really going to drive a lot of the NGL growth here in the United States, and we're well positioned for that. I think Sheridan did a great job of explaining the LPG exports. But it's providing a very constructive backdrop for the future volume growth here at ONEOK.

And if I could just squeeze in a final one. Your condensate splitter in the Gulf Coast, what utilization is that seeing currently? And what's your recontracting time line for that?

It's highly utilized right now, especially with the spreads that we're seeing. And we have just recently recontracted that for term. So that will be contracted here for the foreseeable future and we'll be running at high utilization rates.

Our next question comes from Michael Blum with Wells Fargo.

I wanted to go back to your comment on hedges. You said you entered the year about 75% hedged. Wondering if you can give us a sense specifically on butane blending, if that's the case as well, if you're 75% hedged going into the year? And then is there any kind of seasonality to those hedges? Are they sort of more back-end weighted, front-end loaded or how that plays out?

Yes, Michael, this is Sheridan. We came in highly hedged for the first quarter on the butane to RBOB hedges. We do have some -- had some space to hedge further out into the fourth quarter that we have done that at much higher prices after the Middle East conflict going forward. The thing we're really seeing on butane that's really exciting for us right now is that we're seeing, as I mentioned in my remarks, an increased gasoline volume across our system. That gives us even more opportunity to blend. And you couple that with the synergy projects that we brought online that we think we have some really good tailwinds behind our blending operation, both here in the first quarter when you see a lot of blending and in the fourth quarter when we see the fall blending season come about.

Okay. Great. I appreciate that. And then just wanted to ask the status of the potential Sunbelt Connector project. As I'm sure you're aware, Western Gateway appears close to moving forward. So wondering if there's a possibility that you could somehow join that project in some capacity if it does reach FID or if there's a path for both projects?

Yes, Michael, this is Sheridan again. As I've said before, there's -- we think there's only room for one project. And what we've said before is if either one of these projects go forward, we think it will benefit ONEOK from us being able to bring volume out of the Gulf Coast into the Mid-Continent as one leaves that to go to Arizona on the P66 project. And we also think that we have the ability to supply coming out of the Gulf Coast with the -- us being connected to all the refiners on the Gulf Coast and the ease of getting it into the El Paso area.

Our next question comes from Jean Ann Salisbury with Bank of America.

[Technical Difficulty] You touched on butane blending volumes, being driven by one of the systems. Can you give a little more color about how much more butane blending volume could be physically possible on your system in 2025? Just it would require CapEx, and is that something that you would consider to increase that volume potential?

Jean, you were breaking up quite badly there. It's very difficult to understand what you're saying. Could you try that again, maybe pick up your handset?

Yes. Sorry about that. I was asking about butane volumes and what it would take for ONEOK to increase butane volume on your system?

I mean the butane on our volumes is related to blending. We've been increasing that for the last 3 years. I think every season, we've been able to blend more and more on our system as we continue to go forward, especially as we brought these synergy projects online. So to see a meaningful uptick in our system, what we need is more volume across our system on gasoline, and we are seeing that right now. And we could even see that grow, as I mentioned in there. The rest of the year into the fourth quarter, if you see jet fuel continue to be tightening and prices continue to rise for people to be able to travel by airplane and move more to traveling by vehicle systems.

Okay. That makes sense. Hopefully, this is more clear. Sorry about that. And my other question was that Waha spreads are wider than expected this year. Can you remind us if you lose that exposure over the course of the year or if it's all in 2027 if that goes away?

You're breaking up a little bit, Jean, but I think you said is that the Waha to Katy spread was wider this year in the first quarter than we anticipated, and we were able to capture that. We see that continue through the second quarter into the third quarter when additional pipeline capacity will come online and then it will go back to be more normalized at that time.

And our next question comes from Jeremy Tonet with JPMorgan.

Just wanted to touch on, I guess, the guide and thoughts on EBITDA for the year. If I look at 1Q results and granted there were items that might not repeat. But if I annualize that, that would pretty much get you to the bottom end of the guide. And if I look at last year, I look at the difference between 1Q and 4Q, it's a pretty big step-up and you talk about seasonality over the course of the year. I was wondering if you could just help us think about shaping of the year, EBITDA by quarter, if that's going to vary from your pattern before? Or is there kind of conservatism built into your guidance expectations at this point?

Well, Jeremy, I'd just point you back to the earnings presentation. I think it's Page 5 in there where we've tried to reflect the shape of that as well as demonstrate how the first quarter was the lowest. So we expect the shape of that curve to continue. The only thing that might change a little bit might be an upward slope if we see some enhanced volume in the later part of the year. So no change in the front end and hopefully, a big change in the back end.

Got it. So annualizing the first quarter would -- and that slope will put you over the top end, it seems like. So it seems like a good year shaping up there. I was wondering, as we think about the uplift in the '26 guide, how much of that do you see recurring in '27?

I think we're positioned very well to go into '27 with a great tailwind behind us and really have some nice volume growth and strength. And I'd remind you that we have a significant amount of operating leverage on our Bakken pipeline, on the West Texas LPG pipeline out of the Mid-Continent. So as volumes pick up in the basins we serve, we don't have any incremental CapEx that needs to be spent. All that's going to drop to the bottom line. So we're looking pretty positively as we go into '27. Clearly, we've had some benefit from the differential on the Katy -- on the Waha to Katy that may not be there next year. But our system is diverse, and we find differentials all the time. As we bring on Medford, we might see a pickup in the North-South differentials as well. So we're there positioned to capture those across our integrated system whenever they present themselves.

Our next question comes from Manav Gupta with UBS.

[Technical Difficulty] wanted to dwell into spreads in terms of gaps. There are a couple of pipelines coming on with your involvement also, which will obviously drive higher prices, which is good for your per volumes. But as this gas gets to Katy, there's a possibility you could see somewhat of a gas glut develop over there. I'm trying to understand if that does happen and that South Texas part starts to dislocate from Henry Hub, are there ways ONEOK can capitalize on that opportunity?

I think it's more volume. I think what you're asking about is, could there be a glut in natural gas as we see more volume come on, especially as we see more pipelines down into the Gulf Coast area. Obviously, we're seeing more LNG assets being brought online that will take that volume up. So we don't think we're going to see an overall glut in the Katy area as these LNG projects come on and also as we see more AI projects coming online as well.

And our next question comes from Julien Dumoulin-Smith with Jefferies.

This is Rob Mosca on for Julien. Looks like the final FERC oil pipeline index came in better than expected. Can you help contextualize maybe what this means for your RPC segment and a refresher on how much of that segment is actually exposed to those FERC index interstate oil pipeline rates? And does this outcome meaningfully change your earnings outlook for RPC over the next 5 years?

Yes. This is Sheridan. A little bit, yes. Remember that the spread did come in better than expected, which is beneficial to us. I'll remind you that 70% of our volume on the RPC system is market-based rates, not FERC index. So the impact in 2026 is going to be very marginal as we go in there. But there's a compounding effect as we continue to go forward, that will build on every year, get a little bit more as we go forward. But it's a nice little tailwind, but it's not a substantially change our outlook for the RPC segment.

Understood. And then maybe just turning back to the guide. I was just wondering if the current commodity spread environment simply holds and should we think about it being upside or something additive to guidance for the remainder of the year? I'm just trying to think through how much of that impact you're already factoring into your rest of your outlook.

Well, I think that one of the things that you hear quite a few of -- especially the larger producers talk about is that the back end of the curve right now probably isn't really reflecting the actual physical damage that's been done over in the Middle East. So our expectations would be today that, that curve should strengthen throughout the year. We have not factored any of that into our thinking when it comes to guidance. So should that happen, we'll enjoy that benefit going forward. Clearly, if that results in more volume, that's a positive for us. It takes time to bring on rigs. So maybe we get a little impact in the fourth quarter, but that's going to send us into '27 with a lot of momentum going forward.

Our next question comes from Jackie Koletas with Goldman Sachs.

Just going back to the guide, one more really quickly. How would you frame up kind of the magnitude of the optimization upside that's now expected relative to that $150 million of year-over-year headwinds that was previously assumed?

Well, clearly, we knew going into our guidance that these pipes were going to be constrained throughout at least the first 2 quarters and into the third. So that was factored into our guidance. So as it relates to the Waha and the Katy spread, a good portion of that, it's been a little stronger than we had expected. So we've gotten some incremental benefit. But a good portion of that was already there.

When you looked at the bridge last year from '25 into '26, there was a portion of that was really the hedging that was done in '25 for '26 as it compared to '25 was at some lower pricing. So that was factored into our guidance as well. So really, the potential changes to the upside if we get more volume and enjoy these higher rates on all of that. And then there's still 25% that is unhedged that will enjoy the higher benefits.

That's clear. And then just another -- can you touch on the incremental opportunities within the natural gas segment maybe longer term? I mean, while benefiting from price differentials today, how are you thinking about your exposure to power demand? And how have those commercial discussions trended recently?

This is Sheridan. We have been -- we are in advanced discussions with both AI and power demand right now. We have some very nice projects that are in the queue, and then we actually have projects behind that, that we're even working on as well as they continue to move forward. So we are very excited about what we see in the natural gas demand sector and where our assets sit, especially in the Oklahoma, Texas region for the power and AI demand going forward, and we'll have these projects into 2026 and '27. So it is a good time to be in the natural gas segment for sure.

What I would add, I know folks like to say the same thing is when we first started talking about AI opportunities as it related to power generation, we originally saw those as kind of short lays, smaller volumes, so not necessarily that much of a material impact. As we've now gone through time, and we're talking to more and more of these hyperscalers, the volumes that they're requiring is going to require us to reach back further into our systems and lay larger pipelines. So I think that's the big change that I see from where I sit versus where we were maybe 1.5 years, 2 years ago.

Our next question comes from Keith Stanley with Wolfe Research.

Wanted to follow up on Western Gateway. As you assess what that project could do to the market, do you see it mainly as an opportunity for longer haul volumes on your system out of the Gulf Coast? Or do you think this could create constraints and meaningful new growth investments like the Denver project to expand pipeline capacity?

Yes. I think it's a little bit of both. Obviously, if we start shipping volume out of the Gulf Coast up into the Mid-Continent to fulfill volume that's leaving the Mid-Continent to go on that Western Gateway project, that's going to mean we're going to get a longer tariff because we're moving the volume from a much longer distance away. Also as our -- the tariff from Gulf Coast out to El Paso, it's a very long tariff, one of our higher tariffs. If we increase that volume as well, that's going to have a very nice impact on when it can continue to go forward. And obviously, as we get more demand, will we see more expansion of product on our system? Yes, we will as people are going to shift out of the Gulf Coast more over to our system to be able to get it out to El Paso and to meet this access into the Phoenix and California markets.

Second question, the Bakken volumes were only down 2% to 3% versus Q4. That seemed a lot better than the seasonal guidance that you had pointed to last quarter on what's typical in Q1. So would you say volumes in the Bakken surprised to the upside in Q1 versus what you were expecting?

Yes, a little bit. I mean the winter is always a little bit -- we try to average it out over the 4 months and everything else. So it can be a little bit surprising to us where the winter actually hits and when we see the volume come online. So I would say outside of Winter Storm Fern, we have seen -- we've been pleasantly surprised with our volumes in the Bakken.

Our next question comes from Brandon Bingham with Scotiabank.

I wanted to maybe talk about your Permian processing capacity portfolio and how you see that sort of evolving in light of all this resilient gas production and just seeing some other operators in the basin discuss a more optimistic outlook for run rate capacity additions on an annual basis. How do you see that being incorporated into your portfolio moving forward?

Well, I think Randy had mentioned it already right now, we just put in 150 million a day of the Shadowfax plant that we moved out of the Barnett into the Midland Basin. So we brought another 150 million a day on there that we see that ramping up over time. Then right behind that, we have some low-cost capacity expansions in the Delaware, 110 million a day that will come up later this year. And then we've already announced the 300 million a day plant that we'll be putting in the Delaware beyond that. Those are what we have announced. We continue to look forward. We see a lot of opportunity in the Permian Basin. We're in a lot of discussions on RFPs, especially in the Delaware that we would have the potential to even expand that capacity even more beyond what we see today. I think we see that and also expect that to happen as we get into the -- as we get further into '27, we hope there's opportunities as well. So we are, as like everybody else, very optimistic on the growth out of the Permian.

Okay. Great. And then just wanted to go back to some comments made earlier about better volumes expectations this year as part of the guidance increase. Could you help frame up how the new volumes expectations compare to maybe the various midpoints within the businesses? I noticed the ranges didn't necessarily change, but it sounds like within those ranges, the expectation is definitely better now.

As I said, our increase in guidance was balanced across what we've seen in volumes. And Sheridan just mentioned that we did have a little bit stronger first quarter volumes in some areas than we might have historically expected given what the heater treater impact and that sort of thing would have been. So as we go forward, we hope that builds. And we've taken that and kind of projected it forward. Clearly, I think it still is to be seen what these higher commodity prices are going to do from producer activity. Some of our smaller producers, private equity or smaller independents seem to be a little bit quicker to think about rigs and getting them fired up. So we could see some of that impact a little quicker, where I think the larger -- the larger exploration companies are waiting for that curve to reflect what they think the fundamentals are and then they'll make their decisions.

So we're not trying to get too far ahead of our volume expectations, we'll let that play out. But we do think in this commodity environment and how it's going to look into '27 that we would expect to go into '27 with a really nice tailwind behind us.

And our next question comes from Sunil Sibal with Seaport Global Securities.

Hopefully, you can hear me all right. So my first question was related to the hedging. I think you mentioned on the call that you put in some hedges for '27 also. Could you indicate how much of your total 2027 commodity price exposure is hedged now?

Well, we're not going to get into specifics, but we've taken opportunities to make sure that we've captured at least a portion of what we see in '27. We clearly have been focused on the tail end of '26. So across our various businesses, we've cleared in some portion of '27 at this point. In the markets that we can -- it's probably important to know that in many of the markets that we are serving, there's just not a lot of liquidity in '27 or the backwardation is just so significant that we wouldn't want to do that. So we've been opportunistic, but where we think it made sense, we've looked at it, and we're going to continue to look at it throughout the year.

Sunil, this is Pierce. The only thing I'd add to that is that we have what we call a programmatic hedging program where we just automatically hedge a certain percentage as the year goes by out. So it's not until we see some of these opportunistic opportunities that we go out and do anything like Walt just described. But there is a -- we don't try to time the market or sitting here waiting on something to happen and then move. We just methodically go through the year. And we do that because we're 90% volume times rate anyway. And so we just want to make sure we're not speculating too much on that on the hedging.

Understood. And then one clarification on the potential projects that you're looking on. I think you mentioned in Texas and Oklahoma with the data center clients. Should we think about those as significant CapEx opportunities with some midstream people -- midstream players are undertaking? Or is it should we think about more like incremental CapEx or small incremental CapEx for those opportunities?

Yes. I think as we've gone through and given you some thoughts about '27 and -- beyond '27 into '28, '29 and a run rate, we've looked at kind of a run rate of around $600 million of maintenance, about $1 billion, give or take, of what we call routine growth and a portion of this would be in that routine growth. And then we left kind of another $500 million to $600 million to get you around that -- a little bit over $2 billion kind of run rate going forward, basically unallocated. So these types of projects, while they're bigger than our expectation, we originally thought they'd be $50 million projects, they're turning out to be $400 million to $700 million projects. So they'll fit right in that window that we had left open, and they're coming in at really nice returns.

Our next question comes from Gabe Moreen with Mizuho.

If I could just ask about petchem economics having improved quite a great deal here over the last month or 2. Are you seeing any change in behavior on ethane extraction as it relates to either the Bakken or Cajun-Sibon going into Louisiana? I'm just curious if things have changed on that end at all.

Well, Gabe, you're right. I mean, obviously, what's going on in the world right now, the ethane economics in the United States are very strong, and we're seeing our petrochemical customers operating at very high utilization rate. What it has had to do is we are seeing the ability for our discretionary ethane out of the Bakken and at times out of Oklahoma to be good, be strong, and that's driving some of our -- what we see in volumes as we mentioned. Going into Cajun-Sibon, that's coming off of coming out of the Mid-Continent and out of the Bakken as we divert raw feed over into our Louisiana crackers or Louisiana fractionators. It hasn't really changed that amount on that piece. But as I said before, I think we will see some pretty good tailwinds on ethane coming out of the Bakken and ethane coming out of Mid-Continent through the rest of the year with the demand we're seeing from the petrochemical facilities.

Great. And then if I could ask a quick follow-up. The PRB new plant there, it sounds like it's going to fill pretty quickly. Any visibility to more capacity there? And then I think there was also a callout for Northern Border performance during the quarter. Was that onetime in nature or kind of there's a step-up on ratable earnings there?

Let's see on the Powder River, we've been working on that plant for a period of time. It's a 60 million a day plant. So we mentioned we have a JV partner that's a producer up in that area coming along with us. We are getting more and more excited of what we're seeing there. That's going to fill fairly quickly. Do we see there's opportunity with more volume? Yes, we hope so. In discussions with them, we'll continue to evaluate that, but we do think there's possibility to put some more capacity up there as we continue to look forward.

Northern Border. Northern Border is pretty steady. Outperformance is a little bit. Frankly, we see that kind of every year a little bit that they come in a little bit higher than what they had predicted. We continue to see this year, and we continue -- we expect to continue to see that throughout the year.

What gives confidence in the volumes is the amount of area and dedication. So there's plenty of running room out there to continue to drill there in the Powder.

Our next question comes from Jason Gabelman with TD Cowen.

I wanted to go back to full year guidance. And I guess when I look at your slide deck from 4Q from last quarter, you show that at the time of -- or your initial, I guess, '26 outlook was predicated at $75 oil. That was, call it, $8.7 billion-ish, maybe a little higher of EBITDA for '26. Oil moved down, so your '26 EBITDA outlook moved lower, but we've seen oil now move higher. And I understand the hedging dynamics mean maybe you don't capture all of the upside this year. But would you expect to kind of get back to capturing that upside next year based on where the commodity curves are right now?

So what I would say there is you're absolutely right that clearly, we've got a different realized price environment. So that is going to take some time to work its way through. It also takes some time for rigs to get up and moving. So when you didn't have quite as much rig activity as we had expected, that has an impact that you're starting from a different point as you exit '26. But we think we are going to see that type of strength. I'm not going to give you an actual guide to a number, but we're going to see that type of strength that we expected as volumes pick up. If these prices stay or go higher, especially in the back end of the curve, there's a pretty big difference between the prompt month and as you go out towards '27. So that's going to be the story to tell as that plays out coming forward.

Great. And just a quick follow-up on a comment you just made. Did I hear you right that these -- some of the data center-related projects you're pursuing, you thought they were going to be in the $50 million range and they're coming in more like $400 million to $700 million, those are the right figures?

Yes. The thing is originally, when we go back to that $50 million, that was a couple of years ago when we first started seeing opportunities and people talked about citing these facilities, they were dropping them right next to pipelines, thinking that they could take the gas off those pipelines. Well, when they were doing that, there were -- a lot of them were in the development stage. You didn't have a lot of hyperscalers involved. So some of the specs might not have been quite as realistic.

When the hyperscalers talk about 5 gigawatt facilities, you can't just take that kind of gas off of a fully contracted pipe. So what it's caused, as Pierce said, is for us to need to look at reaching back into our system where the gas is available and building bigger pipe, and that's why the size of the projects have gone up. But at the end of the day, the value of getting these projects done to the hyperscalers is still well above their concern about price. So they're very pleased to provide good economics to make sure that speed and reliability are there.

And our final question comes from Gabe Daoud with Truist.

Just quickly back to the upstream conversations. Just curious if there's any notable difference in behavior or price that operators need to see on the screen as you talk to public versus private? Just curious, especially as it looks like current rig activity is largely dominated by private in the Bakken for your footprint.

Yes, Gabe, this is Sheridan. We're definitely seeing more on the private sector, more activity or talking about more activity than we're seeing on the public sector, especially with the large integrated. Large integrated are still being very disciplined and looking at the pricing environment in front of it, we are seeing -- especially on the private equity side, starting to look more at rigs, more completions and trying to move production up. That's where the majority of the activities happen. I think as we've stated here, as we continue to go throughout the year and everybody expects the back end of this curve to move up as the paper is not reflecting what we're seeing in the physical world. When that happens, I think you could see -- start seeing some more of the integrated and larger companies lean in more at that time or start bringing rigs on that time.

We still are seeing -- even with the larger, we are seeing them making sure they get -- any time they're down, they get things back up and looking to complete wells quicker than they had been in the past. But really concerning rig deployment, that is more into the private sector.

And there's one other element I think is worth mentioning here is that they are really leaning into the efficiency of their drilling and how they're completing and the length of these laterals. So I don't think we need to get too hung up on like numbers of rigs because the ones that are running, they're really putting a lot of emphasis on how efficient those rigs are to make them more profitable per well.

That concludes our question-and-answer session. I would now like to turn the call back over to Megan Patterson for closing remarks.

Our quiet period for the second quarter starts when we close our books in early July and extends until we release earnings in early August. We'll provide details for that conference call at a later date. Our IR team will be available throughout the day for any follow-ups. Thank you for joining us, and have a great day.

Thank you. That concludes today's call. You may now disconnect your lines at this time, and have a wonderful day.

Good morning and welcome to ONEOK's Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]

With that, it is my pleasure to turn the program over to Megan Patterson, Vice President, Investor Relations. You may now begin.

Thank you, Angela, and welcome to ONEOK's Fourth Quarter and Year-end 2025 Earnings Call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are available on our website. After our prepared remarks, management will be available to take your questions.

Statements made during this call that might include one's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

With that, I'll turn the call over to Pierce Norton. President and Chief Executive Officer.

Thanks, Megan. Good morning, everyone, and thank you for joining us today. Joining me on the call are Walt Hulse, our Chief Financial Officer; Randy Lens, our Chief Operating Officer; and Sheridan Swords, our Chief Commercial Officer.

ONEOK has begun a -- become a diversified, scaled integrated and energy infrastructure company delivering durable growth with a disciplined capital allocation strategy. 2025 was a defining year for ONEOK. We delivered double-digit earnings growth, expanded margins and materially strengthened our balance sheet, all while integrating major acquisitions and advancing long-cycle growth projects.

On today's call, there are several key takeaways that I'd like to highlight. First, over the past 2.5 years, ONEOK has experienced an earnings power step change. In 2025, our net income attributable to ONEOK increased 12% to $3.39 billion. Our adjusted EBITDA is up 18% to $8.02 billion. 2025 marked 12 consecutive years of adjusted EBITDA growth, and we achieved a 17% average annual earnings growth rate over the same period. This significant earnings power has been sustained through various market conditions and commodity sites.

Second, we have created an integrated platform advantage. The Magellan, Easton, EnLink and Medallion acquisitions will be fully embedded in 2026 across our NGL of 5 products, crude and natural gas systems, driving scale, connectivity and commercial optionality. We've realized nearly $500 million of total synergies since closing the Magellan acquisition in September 2023, far exceeding our original expectations.

We realized approximately $250 million of those synergies in 2025 alone. And through strategic organic expansions, we built in operating leverage for projects newly completed or nearing completion that will serve contracts in place and allow ONEOK to compete for volumes in the future.

Third, our strategy has created a high-quality earnings mix, with approximately 90% fee-based earnings, limiting commodity exposure and supporting valuation durability. And finally, although lower crude oil prices are expected to slow the pace of drilling, we still have visibility to the growth in 2026 and beyond. Our 2026 adjusted EBITDA midpoint of $8.1 billion is supported by growth completed or near completed projects and $150 million of incremental acquisition synergies.

Related to producer activity in the Bakken alone, there is currently 5,000 identified wells yet to be drilled on dedicated acreage and at current rig rates, that equates to approximately 15-plus years of inventory. ONEOK combine scale, integration stability with long-life assets aligned to meet domestic and global energy demand. And management has proven they can integrate acquisitions and capture the expected synergies to generate additional cash flow.

For 2026, we have good visibility into customer development plans across our iterations with pace of growth being a key consideration for the year ahead. Our guidance reflects disciplined caution around commodity prices, but also continued confidence in our durability of our integrated asset base and the ingenuity of our employees. Through significant growth and change, our employees continue to drive our strategy forward, prioritizing safe and reliable operations and executing on opportunities that enhance long-term value.

I'll now turn it over to Walt, Randy and Sheridan to provide their financial operations, capital projects and commercial updates. Walt?

Thank you, Pierce. I'll start with a brief overview of our fourth quarter and full year financial performance and then move on to our 2026 guidance. Fourth quarter net income attributable to ONEOK totaled $977 million or $1.55 per share and totaled $3.39 billion for the full year. representing a 12% increase compared with 2024 and resulting in earnings of $5.42 per share. Adjusted EBITDA totaled $2.15 billion in the fourth quarter of 2025 and more than $8 billion for the full year. Full year results included $65 million of transaction costs.

During the quarter, we retired more than $1.75 billion in senior notes through a combination of redemptions and repurchases. Fourth quarter activity brought our full year total to nearly $3.1 billion of long-term debt extinguished. In 2025, we returned nearly $2.7 billion to shareholders through a combination of dividends and share repurchases. We also recently increased our quarterly dividend by 4% and further reinforcing that commitment. As we progress towards our long-term leverage target of 3.5x or lower, we continue to gain flexibility in how we deploy capital.

Now moving on to guidance. For 2026, we expect net income at a midpoint of approximately $3.45 billion or $5.45 per diluted share and an adjusted EBITDA midpoint of approximately $8.1 billion.

On Page 7 of our investor deck, we have provided a bridge analysis from original 2025 guidance issued in February of 2025 to year-end 2025 and then a bridge to 2026 guidance. To preempt some of the questions we expect to get on this chart, I plan to walk through each column on the chart to give a brief explanation.

The 2025 guidance was first impacted by lower Bakken volume growth that resulted in gathered volumes being 100 million cubic feet per day lower than originally anticipated. This change in drilling phase began in the spring of 2025 when crude oil prices dropped from the 70s to the lower $60 range. We also experienced a reduction in anticipated NGL volumes with 2 third-party Permian NGL customer plants were delayed for the majority of 2025.

The second column in the chart reflects a $125 million reduction in lower upgrade margin in our NGL and refined products businesses. An example of this would be the narrowing of RBOB to butane spreads in our blending business.

On the positive side, we enjoyed strong location differentials such as the Waha-to-Katy spread and our Natural Gas Pipeline segment. These differentials added approximately $150 million to EBITDA in 2025. The majority of the $85 million of other income reflected on the chart is the gain realized on debt repurchases made throughout the year. On a comparative basis, excluding transaction costs, we ended 2025 with EBITDA and of $8.085 billion compared to our original 2025 guidance of $8.225 billion.

Looking forward to 2026. We see $100 million of EBITDA growth from increased volumes in the Permian and the full year of third-party Permian plant volumes that were delayed in 2025. We -- this $100 million increase is net of other impacts such as contract rollovers and the 18,000 barrels per day of continental NGLs rolling off our Rocky Mountain region volumes this year, which we've previously discussed.

We expect asset optimization to add $150 million of EBITDA for batching and blending logistical benefits allowing us to efficiently move NGLs and refined products through the Easton acquisition connections between Mont Belvieu and East Houston and other synergy projects completed throughout the Mid-Continent NGL and refined products businesses.

The $150 million reduction in EBITDA shown on the chart stems from lower forecasted differentials from Waha to Katy and lower price realizations year-over-year in our GMP, NGL and refined products businesses. We have also not forecasted any gains on debt repurchases of $26 representing the additional reduction of $85 million to get us to a forecasted 2026 EBITDA of $8.1 billion through 2026.

Our expectations reflect an average WTI crude oil price range of $55 to $60 per barrel in 2026 and incorporate normal seasonal dynamics across the business, which influence how earnings are distributed throughout the year.

To help illustrate this, we've added another new slide to our earnings material on Page 8 that outlines the key factors driving results by quarter and directionally shows an earnings cadence that typically builds progressively over the course of the year.

On average, we expect to make a little over $22 million of EBITDA each day in 2026. With the first quarter only having 90 days compared with 92 days third and fourth quarter, coupled with the impacts of weather, we expect the first quarter to be our lowest EBITDA quarter each year.

We expect earnings growth across our natural gas liquids, refined products in crude and natural gas gathering and processing segments supported by continued contribution from recent acquisitions fee-based growth from volumes and completed projects and the continued realization of synergies.

As Pierce mentioned, we expect approximately $150 million of incremental commercial and cost synergies this year. In addition to the nearly $500 million we've captured since the closing of the Magellan transaction 2.5 years ago.

Our 2026 capital expenditure guidance assumes a range of $2.7 million to $3.2 billion, which includes both growth and maintenance. This reflects a portfolio of high-return projects to be completed in 2026 across our system, which Randy will review in a moment, as well as the Texas City export terminal and the Bighorn processing plant.

Capital for synergy-related projects, ongoing well connections and maintenance are also included. As we've discussed previously, we expect capital expenditures to continue to step down in the coming years as we complete current projects, and we do not expect to pay meaningful cash taxes until 2029, both of which continue to support our free cash flow capital allocation flexibility going forward.

I'll turn it over to Randy for an operational and large capital projects update.

Than you, Walt. I will begin with a comment about the impacts of weather in the fourth quarter of 2025 and the first quarter of 2026. Winter weather across our system in the fourth quarter of 2020 and tempered volumes in the natural gas gathering and processing and natural gas liquids segments. But this was largely within our expectations for normal seasonality.

More recently, winter storm burn caused temporary wellhead freeze-offs and challenging operating conditions, briefly impacting throughput in the first quarter of '26We estimate January gathering and processing and NGL volumes were approximately 10% below our original expectations due to the weather. We experienced no material downtime in our own assets, and we have already incorporated the storm's impact into our 2026 guidance.

Now turning to our capital update. Our large capital growth projects are progressing on plan and are currently expected to enter service as anticipated. In the Gathering and Processing segment, our 150 million cubic feet per day Shadowfax plant, which is being relocated to the Midland Basin for North Texas is expected to be in service by the end of the first quarter. We expect volumes to ramp up in activity over time, providing flexibility for our customers in the area.

Additionally, the expansions of our Delaware natural gas processing assets totaling 110 million cubic feet per day. are expected to be completed early in the third quarter. We expect volumes to ramp up quickly as these expansions are aligned with specific producer projects. These expansions help to fill the gap in capacity before our Bighorn plant comes online in mid-2027.

In the Refined Products segment, the Denver area pipeline expansion remains on track for expected mid-third quarter 2026 startup. And lastly, Phase 1 of our Medford NGL fractionator rebuild is on track for a fourth quarter 2026 completion. This will add an initial 100,000 barrels per day of fractionation capacity with Phase 2 adding additional 110,000 barrels per day of capacity in the first quarter of 2027.

These projects extend and expand our existing system, adding needed capacity to address future volumes.

I'll now turn it over to Sheridan for commercial update.

Thank you, Randy. As we sit today, we continue to see opportunities for growth across our expansive portfolio. We expect our Rocky Mountain and Mid-Continent region NGL and G&P volumes to grow at a steady, low single-digit level in 2026. These assets continue to generate stable long-term cash flows that help fund high return growth across our entire platform.

In the Permian Basin, we continue to expect a sustained higher pace of growth due a combination of organic investments and strategic acquisitions, we've established an integrated Permian platform that spans all of our products and services. This integration creates multiple touch points with customers and allows us to capture value across the full midstream value chain.

We saw the benefit of our larger-scale asset portfolio in 2025 achieving record NGL and G&P volumes in the Rocky Mountain region and record liquid letting volumes in the Refined Products segment. Permian Basin processing and NGL volumes increased significantly over the course of 2025 as we continue to enhance our Permian system and add new volumes.

The Natural Gas Pipelines segment once again exceeded the high end of its guidance range in 2025. A benefiting from the strategic location of pipeline systems, specifically in the Permian Basin and Louisiana. The statement's outperformance continues to highlight the strong demand for natural gas transportation and storage and the strategic benefit of having assets in the Gulf Coast region near key demand and export hubs.

Turning to full year 2026 expectations. And starting with the natural gas liquids segment, we expect year-over-year volume growth across our operations. In the Permian, we expect to connect at least 3 natural gas processing plants to our system in 2 including 2 third-party plants and the Shadow fax plant, which we are relocating from North Texas.

New contracts and increasing volume from our Permian plants will continue to contribute to higher volumes beating our West Texas NGL pipeline. This pipeline remains one of the most advantaged pipelines out of the Permian with competitive transportation rates and ample headroom to accommodate future growing volumes. Moving on to the refined products and crude segment. We expect 2026 performance to be driven by steady based refined product demand, increased asset connectivity, continued strong liquids blending and incremental contribution from the fully contracted Denver pipeline project and other [ high-routine growth projects. ]

We are assuming a mid-year tariff increase in the low to mid-single-digit range, inclusive of both market-based adjustments and index-based tariffs with potential outcomes of the FERC rate index review and corporate incorporated into our guidance. We continue to see increased throughput into our long-haul crude oil pipelines from our gathering systems and interconnectivity between these assets has been expanded. Several related synergy projects are underway to fully connect those systems, which we expect to come online this year and in 2027.

Moving on to the natural gas gathering and processing segment. We expect our multi-basin portfolio to continue to provide growth in 2026. Based on ongoing conversations with producers, we're seeing plans to hold drilling rigs and crews steady, while continuing to improve production efficiencies through technology and operational enhancements.

In the Permian Basin, our broad footprint across both the Delaware and Midland positions us to capture incremental throughput while continuing to drive efficiencies across our existing assets and deliver fully integrated services for our customers.

With the Permian projected to grow by more than 1 Bcf per year, ONEOK is well positioned to capture our share of that growth. We continue to see attractive opportunities in the basin beyond those we've already announced.

In the Mid-Continent, we continue to expect growth from our strong mix of producers across the [indiscernible] areas. We have 13 rigs currently operating across more than 1 billion dedicated acres in the Mid-Con. This acreage spans high-producing gas-focused liquids-rich and crude play. -- and we see opportunities under development in each of these areas.

In the Rocky Mountain region, we saw record volumes again in 2025 and expect single-digit growth in 2026. There are currently 12 rigs on our dedicated acreage, but producers heavily focused on continued efficiency gains through improved completion techniques and longer laterals.

We expect approximately 50% of our well connects in 2026 to be 3 and 4-mile [ laterals ]. This is a significant increase in longer laterals compared with approximately 30% to 2025 and 20% in 2024. Gas to oil ratios at the basins also continued to naturally rise, supporting a stable long-term outlook for natural gas and NGLs across the basin.

I'll close with our Natural Gas Pipeline segment, which we expect will have another strong year of performance in 2026. Our natural gas pipelines and storage assets remain well positioned to support growing demand power generation, industrial customers and LNG exports.

On power demand, we are engaged in advanced discussions with multiple data center projects across our operations and are pleased with the momentum we're seeing. Additionally, recent commercial success on our IR joint venture pipeline illustrates how downstream demand is translating into new infrastructure. Strong customer commitments led to an announced expansion to 3.7 Bcf per day from an initial of 2.5 Bcf per day.

And today, we are pleased to announce that all 3.7 Bcf is 100% contracted for a minimum of 10 years. IGA reflects both supply side momentum in the Permian and increasing demand pull from LNG exports industrial demand and other end-use markets along the Gulf comp.

Separately, we expect to continue to see favorable opportunities to optimize our system, particularly in the permanent base to capture natural gas price differentials. We expect those conditions to remain favorable until natural gas pipeline capacity is added later this year.

Our natural gas pipeline assets remain well positioned in our key demand centers and high-growth areas to support long-term natural gas demand. Pierce, that concludes my remarks.

Thank you, Sheridan and Randy and Walt. As we look ahead, we are confident in ONEOK's position and strategy. The work we've done to integrate assets, well operating leverage and further enhance our portfolio is translating into durable performance and resilient growth. .

Most importantly, this execution is driven by our employees. I want to thank our entire team for their continued focus on safety and operational excellence and collaboration. In 2026, ONEOK will celebrate its 120th anniversary. I want to take a moment to recognize the contributions of those who came before us and allow us the opportunity to do what we do today. It is our responsibility to provide the next generation, the same opportunity afforded to us. Thank you to our shareholders for your continued trust and support.

With that, operator, we're ready to take questions.

[Operator Instructions] And our first question today comes from Spiro Dounis with Citi.

I wanted to start with the '26 outlook. Two-part question here. Walt, I was curious if you could talk about maybe where you've built in some conservatism around the guide. I know commodity assumptions maybe looks like 1 area that screens conservative. And Sheridan, in any given year, you seem to find opportunities to optimize and find margin. I know a lot of times, that's not baked into the guidance. I think Rockies ethane recovery maybe is one example. Just curious if you can walk through some optimization opportunities you've been able to realize in the past that you think are upside to the guide?

Sure, Spiro. Well, I think that we think that there's a meaningful potential that we're going to see crude prices in that 55% to 60% range to get some geopolitical influence on it now that's popped it up a little bit above 60%. But we want to plan for that lower level as we look forward.

Clearly, if we get a little stronger pricing that could help our spread differentials that could also provide our producers with more cash flow to drill. So high prices always are a benefit to the higher prices are always a benefit to us. But we think we've been intentional and disciplined as we put these projections together and we want to move towards that $8.1 billion.

Spiro, when I think about on commercially, where we have typically seen upside in the past, and you mentioned one of them is the discretionary ethane out of out of the Bakken, where our marketing team has been done a very good job of being able to lock those in at different periods when they see spreads being wider, not just the average what we see over a year. They've been very successful through that.

We've also had on the GP side, especially the permian, we have a little bit of open capacity. They've been able to have some offloads, some spot off those as they get throughout the year as they continue to work with producers and leverage our customer relationships that have been developed over all our basins into that area, and it can grow volume on a spot basis.

We've also seen that on the NGL as we look about between Conway and Bellevue, that spread at different times of move, and we're able to capture those or bucket going forward are the same things that are our refined products with our normal butane to unlanded spreads that we look to lock them in when we see opportunities as we continue to go forward and then be able to sell those at different times of the year when the spreads are wider than we typically show in our forecast.

Got it. That's helpful. Second question, maybe switching over to the power opportunity. The slides pointed out a step-up in the amount of customers you're engaging with and the potential gas opportunity for you. curious when we can expect some of these deals to start to get announced and what they look like, I think you originally said that they were smaller kind of higher-return projects. So curious if these additional opportunities start to scale up a little bit.

Yes, they are scaling up a little bit, and we are in some advanced negotiations with some hyperscalers out there that we feel really good about. We're hoping that we can announce something in the fairly near future, but we still need to go through the process and get those to bed. But it is looking very positive on that. And we probably have quite a few that we think are in that advanced stages.

Our next question comes from Michael Blum with Wells Fargo.

I wanted to ask a couple of more questions on the guidance. First, can you remind us how much open capacity you have to capture Waha basis spreads? And what Waha spread is assumed in the guidance? Or are you basically assuming there's no spread in '26.

Yes, Michael, this is Sheridan. I don't know if I want to go out and tell you exactly what we have on open capacity, but we do have capacity that we have contracted -- on the [indiscernible] Pipeline system that is above what we need right now for our volume coming up of our plants for netbacks to producers.

We are seeing good spreads right now above what our forecast was as we continue to go forward, but as a forecast for the whole year. And we think that will go through the third quarter before the next pipelines come online, that will bring that spread back together. It is somewhat of a moving target. We are we do see upside and potential upside in that if we continue to spread than where they are now for the rest of the year, rest of the 3 quarters.

Okay. Got it. And then the Bakken, Rockies and Mid-Continent processing volume guidance on Slide 16, the ranges are fairly wide. So I wonder if you could just speak to what you think will drive that towards the lower or higher end of those ranges.

When we think about ranges in there, we try to put it out there because we're dependent on a lot on as producers complete the wells and bring pads on a time and sometimes they will delay those pads coming on at times or they may speed them up at different times. So we try to give a range of where we think it's going to be, and that's what kind of drives it.

And then if we see higher crude prices, you could see producers put another rig on or complete -- put more completion crews on that you could see those growth to more of the higher side of those ranges and beyond. So we're trying to give a range of what we think is reasonable from our experience of operating these assets for many years of producer activity and how just a simple delay for a month or 2 can swing your forecast, or improve.

And we'll move next to Theresa Chen with Barclays.

Appreciate the granularity in the EBITDA bridge and the details related to the synergies -- as we think about these building blocks for 2026, with respect to the $150 million of incremental synergies, underlying guidance, -- can you help us risk weight that? I know Sheridan alluded to this in his prepared remarks, but can you speak specifically on how much visibility you have in capturing these opportunities at this point?

Yes. What I would tell you about that $150 million of synergies that was outlined by Walt is they are all identified, and they are in the plan, and they are underway. -- and as we continue to grow. So we have a very high confidence that we are going to be able to capture these synergies in 2026.

What I would say, Theresa is they will comment the same kind of buckets that you see on Page 9, where we've outlined the different areas where we have been able to capture synergies, and we will continue -- that's where these are going to come from.

And as you prepare to bring online the first phase of the Denver refined products pipeline expansion in mid-2026. What is your outlook for the subsequent phases of this project? And have the expectations related to the Denver refined product system changed at all and parlaying this to another component of your potential pipeline portfolio. Can you provide some incremental color on the commercialization efforts related to Sunbelt?

The first thing on the Denver expansion, yes, it will come up, as we said, mid-third quarter -- it's fully contracted with take-or-pay volumes, so will come up right away during that period of time. As you can imagine, our commercial team is out there working diligently right now to bring the Phase II online as we continue to go forward. We have some momentum in that area, and we're hoping that we can commercialize that sooner rather than later. -- as we go forward because, obviously, it's a very nice add-on project.

We built that -- we build operating leverage into that pipeline a bit out there. When we think about the Sun Belt Connector, I had said last time that we had -- we had an open season that had a lot of interest in it, but not enough to FID. And we still believe that the other project out there still does not have enough to FID as well. But we do think we bring in value to bringing volume into the Phoenix area by having access to the Gulf Coast. And our connectivity that we have extensive connectivity that we have through our system and tied into all those refiners down there that we believe that there is an opportunity to be able to work together to be able to bring this much needed project in FID.

And we'll take our next question from Jeremy Tonet with JPMorgan.

Thank you for the helpful information with the bridge here. I was just wondering if we could bridge maybe just a little bit more. If we take a look back, there's been a number of acquisitions in the past several years here. And just wondering if you could expand a bit more on which ones are hitting expectations or really which ones might be coming in a little bit below such as EnLink, just trying to square acquisition expectations versus the outlook for '26 at this point?

Well, Jeremy, clearly, the Magellan we've had the most time to play through the synergies there, spend a little capital where necessary to make the connections, the get the logistical benefits. So we definitely have the most progress on the Magellan transaction. And the synergies to date have been weighted in that direction. -- remember, it's just now been a year since we brought in and things are going according to plan.

I think that they're at the pace we -- at the time we announced that transaction, we said that there were some contractual arrangements at EnLink that we're going to take a little bit of time to roll off and those volumes would come over to our pipes. So we're still expecting that.

And Medallion, I think we've been able to jump into it pretty quickly by being able to bring our balance sheet to the full to bring volumes on to our long-haul crude pipes and really just to enhance the gathering system by providing the full integrated service. So I think they're all on base. with Magellan clearly leading the way just because we've been at it a little bit longer and it's opportunity that might be a little bit bigger given the overlap of our assets.

Got it. Understood. Maybe coming at a slightly different direction here. I think there was the expectation for the potential for EBITDA to approach $9 billion going into next year here. I'm just wondering I guess beyond lower commodity prices, are there any other kind of drivers to the delta with the current outlook?

No, I think that -- the difference in our outlook has been really more -- it's twofold. It's producer activity. we clearly saw $100 million a day of lower volume than we had expected in 2025. So we haven't caught up on that yet. And then with the lower prices, you do see a narrowing of spreads across the various businesses.

So I think it's pretty much as simple as that. volumetrically, we our expectations are down a little bit. We still see the building blocks that we have ready to come in here in 2026 that will drive us into 2 like the Denver expansion that Sheridan was just talking about as well as Medford coming on and the shadow pax plant. So we've got some nice adds throughout that will give us some strength as we roll into 2027 regardless of what the commodity environment is.

We'll move next to Jean Ann Salisbury with Bank of America.

Can you talk through the drivers of your NGL throughput volumes on Slide 14. Your 2026 guidance is forecast basically flat versus 2025. To your point, given growing gas-to-oil ratio, we would expect growth in NGLs in all of your basins. So if you can kind of just walk through and talk about market share loss or ethane recovery changes, but why overall, you kind of have that flat?

I think when we think about on that, I'll just start with the pocket and walk through a little bit in there is obviously in the bucket we've talked about it for a period of time. We have a contract coming off this year. We're going to lose about 18,000 barrels a day. going over to the Kinder Morgan system.

So we're still going to see growth in that, but that's going to temper that down a little bit. In the Mid-Continent, it is an ethane story, our C3+ is growing in the Mid-Continent, but we are predicting a little bit more ethane rejection in 2026 than we did in 2025. The Mid-Continent is also an area where we have been able to do some incentivized ethane or discretionary bringing some discretionary ethane on in that portion, and that's not predicted and these numbers continue to go forward.

And then the Permian we are expecting some nice growth uptick on that, and we do expect that to be in full ethane recovery. So it's kind of a little bit of, let's say, in a nutshell, that's our ethane assumptions through our systems that we have in there and also the Bakken with that volume coming off I would also say that we do not have -- we had a very good year last year on discretionary ethane out of the Bakken, and we have not predicted to be at that same level this year.

Okay. That's very clear. And then I kind of just wanted to follow up on Michael's question. So the Waha-Katy spread is still pretty wide for 2026. But it seems like maybe you didn't put all of that into the guidance. But I guess my question is just like in '27 when all those pipelines come on and that spread basically disappears, should we expect like basically a further material step down in that bucket in '27.

Well, what I would say is we contracted for that space on Eiger and to be able to provide a service to our customers that we're bringing through our gas processing plants that give them and outlet for their gas to continue to go forward and when we market that gas for them to make sure they have a good netback and that gives us advantages to attract more gas to our system.

But as we bring more volume onto our gas processing plants, that volume is all being used right now and the extra volume is what we are able to sell at the spread. So as we get into we are predicting that, that volume will be used for our G&P business and the natural gas that's coming off our plants to serve our customers.

Thank you. And we'll move next to Julien Dumoulin Smith with Jefferies.

This is Rob Mask on for Julien. So maybe related to that $55 to $60 per barrel assumption, do you think it would be fair to assume on a go-forward basis that at that level, you'd expect your Bakken G&P position to grow -- and maybe if not, what other factors could alter that correlation?

Well, I think we've come out and said that it's 55% to 60% is what our prediction is going forward. And yes, at that we -- at this crude level, we are seeing a low single mid- to low single-digit growth rate for the Bakken volume, both on the NGLs and on the G&P side of it.

Obviously, in a higher crude environment as producers have more cash flows, they're operating within cash flow today as they have more cash flow, and they feel like they can deploy more rigs for that additional cash flow, we will see increased volumes coming out of the Bakken and be able to continue to grow our position.

Obviously, we have a very large position in there right now. So it's really about growth across the whole basin continue to go forward. So we really see it as to get beyond that 1% is probably going to be driven by more commodity price increases. As we continue to look out forward, though, we are seeing that producers are continuing to work on efficiencies around longer laterals and efficiencies on completion techniques as well as starting to see the toy around with more refracking and reworking older wells that can bring more on as well. So we look into the future, we think there's some other factors that could tend to push the Tier 2 and Tier 3 acreage into more economical limit at a lower price environment.

Got it. That's really helpful, Sheridan. And for my follow-up, I'm wondering if -- if you could provide an update on how you're angling to get more third-party volumes onto your Permian NGL system. And what are your plans if you need more capacity beyond nameplate given that the 4Q number was strong you're adding more plants and you have a pretty modest-sized NGL package rolling to you in 2027.

I'll start with the capacity. We still have right now roughly around 300,000 barrels a day on our West Texas NGL pipeline. Remember, as we continue to look that system. We finally had to look the whole thing and now we're sitting at well over 740,000 barrels a 1 system.

As we continue -- and the question about being able to track third-party volume to our system, there are still G&P operators out there that are not associated with the NGL pipeline that are looking to move on an NGL pipeline. There's out there today as well as there's a lot of producers out there that have taken time rights at existing plants that we were able to contract for that were already connected to or can be connected to. So even though those plants may be owned by somebody that is associated with the long-haul NGL pipeline.

And we've been able to execute on both of those at the time and we see opportunities going forward, not only in '26, '27 and beyond that we will have those opportunities to be able to tice that volume to come here. And with our -- with this very advantaged capacity we have on our NGL pipeline and advantaged frac capacity we'll have at Medford. We think we can speak for those very well.

And we'll go next to Manav Gupta with UBS.

Good morning. Your slide deck references natural gas storage opportunities. I was wondering if you could comment a little bit more about them, which are the areas geographically where you're seeing most of these opportunities. And also, are these opportunities tied to data centers or it's a combination of data centers and LNG export projects. If you could talk a little bit about natural gas storage opportunities?

Yes. What I would say is I'll kind of break our natural gas storage opportunities into 2 areas. One, first area is Texas and Oklahoma, more on the legacy ONEOK system. And that has mainly been driven by utilities going in there. We've expanded those a couple of different times. We see opportunities to be able to expand them more. We continue to see if there's opportunities for us to expand. Right now, those are fully contracted under long-term contracts.

When you get over to Louisiana, with the EnLink acquisition, we are putting out the GIST expansion that we will go from, I think it's 2 Bcf to about 10 Bcf and as we go there. That will come on in 2028 that has been contracted as well. We do see some more opportunities out there to grow more storage. There's another opportunity to grow to expand [ just storage some ] more, and then there's the pull storage over there, and we think that there's an opportunity to grow as well.

We have teams, engineering teams and geology teams looking at that see what can do go forward. Those are going to be more driven by industrial customers and LNG people that are going to want to need those systems and where, which we've had a lot of inquiry into that. So we do see a lot of upside on the storage and natural gas beyond 2026 and beyond.

My quick follow-up is what are you seeing in terms of refined product demand in your system, we are off to a very surprising year where you have seen massive goals, so probably higher on the diesel heating oil side, but maybe a little more on the gasoline. But in your system, how are you seeing the refined product demand rate? If you could talk a little bit about that.

What I would say so far through the year. I mean, it -- you got to be careful to be cycle a little bit through the year. But so far, as we come off in the first quarter, we are seeing good demand, especially on our West Texas system, Alto El Paso, which is very, very encouraging.

Now we got to be careful a lot of times demand swings will change based on refinery turnarounds and what's going on in the system. But so far, we've been very good. The central system through the Mid-Continent is performing at or above our expectations for the first quarter going forward. So we are seeing some good demand pull across our system.

Our next question comes from John Mackay with Goldman Sachs.

I wanted to touch on the '26 CapEx guidance. Can you tell us a little bit more of a breakdown of where those dollars are going in terms of kind of the bigger projects coming on maybe over the next 2 years? And then on a related note, how you're thinking about kind of all-in return profiles for that capital ledger?

Sure. Well, the keys are the ones that Randy mentioned that we could come here in 2026, the Denver pipeline expansion and the refined products, the shadow fax plant, the first phase of Medford coming on. Those are all right on target and will be additive as soon as they come on. Then we have a couple of rolling over into the first 6 months or so of '27.

And then our larger projects really have been completed and we'll be on to the more ordinary course, what we call routine growth, expanding and extending our system we've been out there and said that we spend about $600 million, give or take, on maintenance, kind of about $1 billion on routine growth every year, and then we managed to find $400 million, $500 million of other larger capital projects that we -- our commercial team is always out looking for and that backlog is building.

So -- but we don't expect any -- we don't see any real large capital projects like mile pipeline or something on the horizon at the moment. Clearly, the one we haven't mentioned there is our joint venture on the dock, which will wrap up as we go into 2028.

And then going back to, I think, maybe Rob's question. capturing more Permian G&P volumes. Also earlier in the prepared remarks, you kind of pointed to potential inorganic opportunities in the Permian. Can you talk about that a little bit more for us? And maybe potentially what your experience with synergy capture informs what you could be considering?

Well, on we think about G&P growth in the Permian, with the growth that we're seeing now in 2026 is from mid- to high single digits, and that's based on contracts that we have today coming on board.

We're also seeing plenty of RFPs out there come forward that the volume, either coming off contract or new volume being drilled that we have a very good chance of being with a capture, especially when you think about a lot of these customers are customers for us in other basins as well.

So we feel very good about capturing more volume on the G&P side going forward. The great customer feedback that we've had and what we've done so far. We have -- we -- as I told you last time, we're at the Shaderfax plant and the [indiscernible] in Delaware has given us a little bit of operating room to be able to grow with these producers, and that's what they really were missing when EnLink was operating these assets.

As we think about inorganic growth, I think in the comments we were talking about was more about we built a platform with the inorganic growth that we've done so far. We're really concentrated at this time on the organic side of it and how do we connected up to the wellhead or to the CDPs that are out there and concentrating on these RFPs that are in front of us that will continue to fuel volume growth '27 and beyond.

And we'll now move to Brandon Bingham with Scotiabank.

Just looking at the $150 million headwind bar on realized pricing impacts for the guide. I was just wondering what you guys are assuming price-wise within each of those buckets and how that might compare to current strip prices and then what the potential uplift could be if you sort of mark-to-market those assumptions?

What I would tell you about is those -- when we put that together, we were at a $55 to $60 or we're going on based on a $55 to $60 price environment. What we typically see, as we think about those headwinds is that is on the spread business, we, as crude prices are higher. We typically are wider. On our commodity exposure, that's mainly in the G&P business.

And we have a systematic program of hedging, and we only -- we try to leave only about 25% open on our commodity exposures as we continue to go forward. So as we think about going forward, that's more like a -- we would see some improvement in crude prices from the $55 to $60 range, we'll see upside into our spread part of the business.

Okay. And then maybe just one quick follow-up. Just haven't heard much on the Texas JV with MPLX. Just curious if you have anything to share, we're kind of the latest and greatest there? I know you mentioned as part of the budget for this year, but just kind of any update you can provide?

I mean it's progressing. The build side of that is resin is progressing as planned, very satisfied as we're going on that. On the commercial side, is there -- we are continuing to advance the commercialization of that dock. We like where we are today. The momentum is strong where we are today, continue to have a lot of customer interaction with that, a lot of interest moving forward with quite a few people on that going forward. So we like where we're at, and we're excited about that.

One thing I'd add to that is that we have multiple touch points at different levels of MPLX in here. And I'm very, very pleased with the communication that's going back and forth. -- between the 2 companies, excellent collaboration.

We'll now move on to Keith Stanley with Wolfe Research.

I wanted to ask on capital allocation. Would you expect excess free cash flow this year to go to debt repayment where do you see leverage ending the year? And when would you expect to get to that 3.5x target roughly?

Well, I think the -- it's important to recognize that our 3.5x target is a self-imposed target. The agencies for our current credit rating provide us a little bit more flexibility at a higher debt-to-EBITDA than that 3.5% target. So we believe we have flexibility from a capital allocation standpoint as we look forward and have clear visibility down to the 3.5%. So we may or may not be a little bit opportunistic if we see opportunities in the capital allocation side.

But we're still on target clearly with EBITDA expectations lower than they were in 2025 guidance. our denominator has not been as strong as we thought it would. So it's going to take a little bit longer than we originally expected. But we're on track and we're aggressively reducing debt through 2025. And we still have a pretty strong CapEx project this year, backlog this year. So -- we won't be able to lean in too much into the debt reduction until we start to complete those in the second half of '27, you see that incremental free cash flow really kick off.

Second one on the bundled NGL rate in the Bakken, it slipped a little to $0.27 in Q4. Was that increased ethane recovery and what would your expectation be for 2026 on your rate there?

Yes. That's increased ethane recovery of what you're saying is we had a pretty good fourth quarter with ethane recovering in there. We're still run that trains going over. A lot of it is driven by how much ethane we bring on what different contracts come on going forward. There is a little bit of difference between some of the contracts out there. But yes, it's going to be in that in that 30-ish range.

And we'll go next to Jason Gabelman with TD Cowen.

Most of my questions have been answered, but maybe I'll just ask 1 more on the M&A front and more related to the RP and C segment given the success in the Magellan business and kind of your unique footprint there. You've been growing in a segment that most peers have a small or nonexistent footprint. So perhaps you're better positioned to consolidate that part of the value chain. Is there a desire to further grow the P&C business inorganically?

So Jason, this is Pierce. I was wondering when the M&A question would come up. Our focus continues to be on executing for 2026 plan and beyond. And we don't see any really glaring holes in our portfolio right now. So we're really pleased with what we got. We're going to continue to look at things that fit our strategic objectives and especially as our criteria and the questions around that. And we're going to continue to be intentional discipline in our approach to M&A. So that's adding RPC or adding different things, then we're going to look at those. But we're going to be really intentional about what we're doing.

Thank you. At this time, we've reached our allotted time for questions. I'll now turn the call back to Megan Patterson.

Thank you, Angela. Our quiet period for the first quarter starts when we close our books in early April and extends until we release earnings in late April. We'll provide details for that conference call at a later date. Our IR team will be available throughout the day for any follow-ups.

Thank you for joining us today, and have a great day. Thank you. This brings us to the end of today's meeting. We appreciate your time and participation. You may now disconnect.

All right. This is the session for ONEOK. You've got to my left, Sheridan Swords, EVP, Chief Commercial Officer. next we've got Pierce Norton, President and CEO; and Walter Hulse, EVP and Chief Financial Officer. So thank you, gentlemen, for joining me. Appreciate it.

Thank you, Mike.

Welcome. This is open Q&A. So feel free to just raise your hand and any time during the session, and someone will come over with the mic and you can ask a question. So maybe I'll start -- yes, I guess I'd start just high level over the last few years, you've made some pretty significant strategic shifts in the company, diversifying your Bakken concentration, adding more basins, refined products, crude, NGLs, reducing your gas -- natural gas exposure. Maybe you could just talk through that strategic shift that you've undergone at a high level. Do you like where the company is now from a mix of assets, markets, cash flow stability? And is this kind of what you're aiming to get to?

Okay. So I'll take that question, Michael. I'd probably start out by saying that in 2021, in the middle of the year, we had decided as a management team that we did need to take a strong look and really assess our competitive advantage. And so I'll kind of tick these, you mentioned what we've done several acquisitions, which is true and some very large ones. But I'd start with Magellan. So what Magellan brought to us was what we call demand pull, where we primarily had producers that was a supply push, and we wanted to get into a demand pull kind of situation. So that's one of the things that it gives us because we got much larger in the refined products business with jet fuel, diesel and gasoline distribution.

So that's -- and it also brought to us cash flow stability, brought to us the ability to sustain the earnings with minimum capital, although we have found ways to enhance and extend some of the systems that we had -- that Magellan had. Then the next one was EnLink. EnLink got us more into the Permian. And if you'll notice, there's a certain order that we went to this. We -- and then we had Medallion, which actually got us into the crude gathering business and was able to connect up to our long-haul pipes that we got from Magellan.

So we would have never done Medallion had we not done Magellan first. The EnLink stuff, all of those assets were pretty much on islands. Our assets connected all those. So the whole thing really flowed into our strategy. We want to touch as many molecules as we can for basically as many times as we can for as long as we can. So that's our -- that's the premise of our strategy.

You did mention one thing I want to address, though, you mentioned us kind of reducing our exposure to natural gas. That is true on the interstate side. And there was a strategic rationale for that because those, it didn't fit with our molecule strategy. It was isolated. We could only touch those molecules one time. The company we sold them to, they had many more options to do connect to storage and already connected some of their other assets. So it would be more valuable to them than it was to us. So we did divest of that, but we have actually grown the intrastate side of our business through EnLink and also in the storage side of our business. So we've gotten much bigger on the intrastate side, which is really where we like to be because of the connectivity and then the molecule storage strategy.

So I guess with all this M&A activity, I think one of the hardest things for investors and us to really get a good grasp on is the synergies. I think you've outlined $700 million to $1.1 billion of synergies across all this. Can you just make us -- maybe just walk us through the major categories of synergies, how far along you are to achieving those and when you expect to have all those synergies complete and reflected in EBITDA, if there ever is an end to this?

Sure. Well, I think what -- where I would go with that is start again at Magellan and kind of walk through sequentially. The Magellan acquisition from a synergy standpoint has far exceeded our expectations. I think we've probably been able to capture 80% of what we thought was there and then found a whole lot more than we had expected. And the reason I think that we found so much more was that they really had limited the capital that they put into the business to about $100 million a year. And effectively, that kind of shut down the organization for looking for opportunities. So there are a lot of real small opportunities where we'd spend $10 million and get $8 million of EBITDA. We have one we spent $12 million, and we're getting $30 million of EBITDA. So some really nice, very high-return projects, but they fall into buckets.

The first ones we get are the easy G&A. You can kind of knock those off. Sometimes they take up to a year to get them because of contractual types of things. But for example, insurance, we've been able to fold some of these operations into our insurance and completely eliminate the cost that had been there before. And then the next is things like I just mentioned, the smaller capital projects, quick hits, connects, things you can do. And those have been coming in line, and you've seen them so far, and you'll see them again when we put out the fourth quarter in the refined products business.

And then the last bucket is the biggest bucket, and that we like because we have total control over and have had total control over all these synergies with Magellan is that there were some big connections that we had to make to really interplay our NGL system down in Mont Belvieu with the Houston distribution of both refined products and crude that Magellan had. And to accelerate that process, we bought a small little pipeline company called Easton. It kind of -- we were already a customer on Easton. It accelerated by about a year our ability to connect Mont Belvieu to those other Magellan properties. That has just completed. Those connections were just completed here in the third quarter. So we're now starting to see the benefits of that last wave of synergies where we had to spend some meaningful amounts of capital.

We did the same thing up in the Mid-Continent. We're not quite done there yet. We're just in the process, but where we've connected our Kansas NGL network to the distributions across the Mid-Continent and into Cushing with Magellan. So we're way ahead of where we expected to be with Magellan.

Medallion, that was kind of a plug and play. Most of the synergies that we got there, again, were within our control, but really came around our ability to operate those assets in a way that Medallion couldn't because they just didn't have the balance sheet. They had to really let third-party marketers come into their system to handle product. We've been able to remove the third parties and be able to go directly to the customers and then fill our pipes, which is another synergy that's within our control.

And then EnLink, we're just now -- we're about 9 months, 10 months into it. Coming along, the corporate synergies are just about all falling to the bottom line. You're starting to see some of the contractual synergies over the next couple of years that will fall in, and those are primarily NGLs that will roll off contracts from other pipes and then fall on to our system. So we feel and we've got a slide in our deck that we're ahead of schedule as it relates to synergies and that what we really have tried to do is make sure that the vast majority of those are within our control and ones that we aren't waiting for a customer to do something where we do have some of that contractual stuff, but we're right on path.

Great. Maybe we turn to the macro a little bit. Maybe just get your general thoughts as we head here into 2026 and maybe specifically drill down a little bit on the Bakken and the Rockies in terms of the volume outlook in the remainder of this year and then more importantly, into '26.

Speaker.

Okay. So I'll let Sheridan take the Bakken question, but just the macro level view of what we have, Michael, is that there is going to be about 13.5 million barrels of oil that's produced here in the United States. And most of that gets consumed locally and what doesn't goes across the water. I think the LNG picture that's developing around the Gulf Coast, you heard the term 30 at 30, which is 30 Bcf a day of capacity coming out of the Gulf Coast area by 2030. That's a significant amount. It's almost double what we have currently.

That gas has got to come from somewhere, and it's probably going to come from the Permian and the Haynesville, at least in the near term until something could potentially get done out of the Appalachian area. But that is significant. And then you add on top of that, the AI data centers and the electricity because speed to market is what they're really looking for. And so they're locating these data centers in and around where the producing areas are. It's going to give opportunities for multiple pipelines.

In our opinion, you're not going to see any large -- unless you went into spending capital for the electric generation piece of this, you're not going to spend a lot of capital on the pipeline side because they're locating them at or near several pipelines because they don't even want just one pipeline servicing these areas. They'd like to have multiple. So they have backup because of the reliability issues. So I think that's going to be a real driver for natural gas.

And even in a flat crude environment, you're going to see the growth because of the gas-to-oil ratios. So we're going to continue and there are areas out there that do have liquids in them that are not necessarily. So you got casing head gas that comes with the oil production and you got your gas flow gas that's either dry or your gas well gas that's got some liquids with it. So all of those are going to continue to grow, which means just more liquids for us and filling up our assets because we do have the operating leverage both out of the Bakken, out of the West Texas area and with the fractionation that we're putting back in at Medford. So you can answer that.

Yes. Michael, when you think about the Bakken, the Rockies, as you think about the growth out of the Rockies right now, we saw growth from '24 to '25 into the Rockies, and we're going to see growth into '26. The crude oil production, we think, is going to stay relatively flat up there. And with the GOR, you're going to see low single-digit kind of growth on the gas side of that. The good thing in the Rockies right now, we have capacity up in the Bakken. We have processing capacity. Our capital is going to be lower than you've seen in the past because we've built that operating leverage that we've talked about before that we were able to grow in as we continue to grow.

Right now, in the Bakken, we kind of see what happens every year, and we've got to plan on it. It's you haven't looked up there, I think it's like minus 9 right now. So it's -- which is normal for them, but we do see heater treaters come on at this time of the year. And so we always see a little bit of dip in our volumes in the fourth quarter and into the first quarter. So nothing unusual right now going on volumes right now.

We continue -- we have talked to a lot of producers up there. The big ones ConocoPhillips, and they are going to continue to go forward strong. They're going to drill through this. A lot of the big boys are going to drill. and ExxonMobil, they're all going to kind of keep their drilling programs that they have going on. We are seeing some private equity in certain areas get a little aggressive at this time because this is their area that they're going to drill. That's all they have. They have this. And there's a lot of areas up there at this crude environment that people can make money at. This is their one area to grow. So we're going to see them continue to grow some volume out there. So you take that, that's why we think we'll see kind of low single-digit continued growth up there in the Bakken.

Maybe just on the Bakken. So I think Bison Express starting up, I think, Q1 '26. And just curious with the start-up of that gas residue pipe, if that has implications on your ethane recovery as you look out to '26. And if I recall correctly, you usually don't put much in the guidance for ethane recovery. It's more of an upside optionality. But yes, just curious if -- what you think about that.

One of the thing about Bison, we need a little bit more gas. A lot of that's been contracted, continue to go on that. And that comes on. I don't see it having too much of an adverse material impact on that. A lot as you see basically just the difference between having gas up in the Bakken versus Henry Hub, which is really, when you talk about our discretionary ethane, that's really what we're doing is we're natural gas out of the Bakken to the Henry Hub price because we're buying -- basically buying the ethane off of a natural gas price up there. So I think that's still going to flex a little bit. But I don't think all of a sudden, you're going to see the Bakken price have substantial move to Henry Hub price and then what you've seen is history.

Maybe back to Pierce's 30 at 30 comment, I like that one. There's been some talk or chatter lately about Mid-Con permits and maybe rigs ramping up to support some of this LNG build-out wave over time. So you guys are a big player in the Mid-Con. So curious if you're -- what you're seeing there or hearing there on that front.

Yes, Mike, what we've seen is that as Pierce kind of talked about it, when you have all that demand for gas and you're starting to see gas prices in really nice attractive levels, you're in the high $4 and especially when you see crude at this $60 range, you're seeing a lot of the producers try to go to a more gassier or what we call the condensate window. And the Mid-Continent is prime for that. It has an oil window, it has a condensate window, then it has a little bit of dry gas window. And we are starting to hear producers talk about into 2026 in the Mid-Continent moving more to that condensate window.

And the condensate window, I mean, the gas is still rich. It's a very rich gas. The thing that we like about it is it IP is at a much higher rate than we see in the oil part of that window, continue to go forward. So that -- we've always felt the Mid-Continent has been kind of our high gas price option that you'll see more volume come on, seeing more of that. And that doesn't take into account. We're still seeing that I've talked about before in the western side of the state, the Cherokee formation that has -- we've got a lot of people very excited about that formation over there, which is still a little bit oilier, but it does get some pretty good gas coming out of there, and they're continuing as we've talked to them, they are wanting to continue to drill that out, explore that, expand that as well.

So for a long time, the Mid-Continent, we've kind of called it to be flat going forward. But now it continues to become more and more exciting for us for increased volume growth. And obviously, we've still got a very nice position on the NGL outlet where we get most of the NGLs coming out of the Mid-Continent. And with our EnLink acquisition, we've more than doubled our G&P presence in there. So all that as we continue to grow, we have a wider footprint, we can handle our area.

That was one of the synergies that we had with EnLink is EnLink has a very large contract with one producer that there are certain parts of it, they could not service because they were not close enough and it became uneconomic for them. But when you put the legacy ONEOK system with that expands our reach and now we're able to get some very nice -- not get -- we have that contract. We just don't have to release those acreage. So that's been very nice. So we continue to see that growth in the Mid-Continent and pretty excited about it.

And the demand side is actually growing there because after COVID, we saw a lot of influx of people coming into the Oklahoma area. Oklahoma has always been a net exporter of gas. A lot of people don't realize that even during the dead of winter like January, February, the Oklahoma area producers have exported around 3 Bcf a day. So the -- and the capacity and the volumes have been larger than where they are today, even though they're growing. So the capacity is there to export the gas from Oklahoma and you just need it on the demand pull side, which that's what the LNG is going to do and the data centers.

So maybe if we shift a little bit to 2026. I realize you're not going to give us guidance right here. But if you want to go ahead, but you're probably not. So maybe you can just walk through at a high level, how we should think about what are the drivers of growth in '26 versus '25? How big a factor is volumes versus butane blending spreads? And then within that context, on the third quarter call, you kind of pulled back your 2026 outlook. So can you also just speak to that decision?

Well, the good news about the growth into '26 is it's really driven by the projects that we've been working on and completing. I had mentioned before the Easton connections that just finished up in the third quarter. We're going to enjoy those here in the fourth quarter, but we'll get a full year of them going into '26. Those connections that we've made up in the Mid-Continent that we're doing right now in the fourth quarter, we'll get all of those in '26.

We'll bring on the Bison pipeline, which was mentioned here a second ago, which actually sends gas down to the Cheyenne market. That will come on. That's fully -- that's contracted. So that starts day 1 when it comes with those contracted rates. And then we've got the Denver expansion of our refined products pipeline, which also comes in, in '26. So we have a lot of kind of stairstep items that will fall in that are not reliant on the drill bit.

As we look at '26, one of the reasons you highlighted the spread between butane and RBOB. It's been about its lows here through most of '25. We've kind of got that marked into our view for '26. So any upside that we get there is will fall to the bottom line. But I think really where we -- why we backed off is as we saw crude go from a $75 price, which is where we were when we started to put that outlook out there to a $60 price, we've just seen producers kind of back off a little bit. They haven't stopped drilling. They still have the same number of rigs.

But I kind of use the analogy, they were going 75 miles an hour they're still going fast, but they've kind of backed off and they're going 60 miles an hour now. So just not leaning in quite as much. So on the margin, while we think there's still going to be growth, it's not going to be as robust as we thought it was going to be.

Maybe just also on '26, just as we think about the major capital projects that are on the board and how do we think about just directionally '26 CapEx versus '25?

Yes, '26, there's quite a few of them that were in the process here on '25, still continue in '26, get wrapped up in '26. I mentioned the Denver pipeline. We get the first phase of the Medford frac done in fourth quarter of '26, and then we get the second phase in early '27. Those are 2 bigger projects that roll off. So we'll start to see that real kind of reduction in CapEx in '27. But '26 is going to be pretty similar to '25.

So maybe just to round out this topic, M&A. You've done a lot as we discussed. Would you say that -- what is your appetite for M&A at this point? Do you feel like you've basically built out what you want to build out? Or do you feel like there are still areas where you'd want to fill in?

Well, I think we always -- back when we got together in '21 and came up with our key criteria that we were looking for, there are several of those things that still exist. Do we -- would we like to have even more free cash flow. Yes. Would we like to have maybe a little bit more scale? Yes. Do we want to continue to diversify? Do we want to expand and extend on our existing assets? The answer to all of those is yes.

But we are in a position now because of our asset mix and the opportunities we have on synergies that we can be patient about this. And everything that we know exactly right now what it is that we would like to look at as it relates to M&A. But we don't feel like any of the things that we would be really interested in are necessarily what we would say, well, we've got to go get something done today. So we think we can be patient, and we can, again, be intentional and disciplined in what it is we're going to do on the M&A front. I mean you can see by what we did of doing Magellan and then doing EnLink and then doing Medallion and then Easton is in there. All of that stuff was very intentional, and we could see how all those pieces came together that fit the puzzle that we have today.

Can you folks describe the wellhead to water strategy and just the competitive landscape as you see it today?

Yes. I mean the wellhead-to-water strategy is just basically we have customers and everybody else that wants to give us natural gas, go through our processing plants, take their NGLs down the pipeline and be able to move it across the dock as we go forward. We have some producers that want that as well. Also from our side, we look at it is we want to control our complete destiny, meaning that as we get liquids down into the Mont Belvieu area, we want to make sure they clear into the market center.

And we decided that we've been looking at the LPG dock for 10 years and trying to understand when do we need to get into it? What's the right time to be able to, what are all the issues. Through all that study, we found there's a couple of things that we wanted. One thing is we wanted something off the Houston Ship Channel. That's what a lot of our customers wanted us that way. We wanted to have a nice be able to have a green brownfield that the cost isn't so much. That's what NPL brought to us as well. But most more, we want to be able to clear our liquids out there.

Our liquids today are already moving across other docks. We're not contracting across other docks, but they are moving across other docks. But we went in and looked at it and looked forward into the future and said there's going to become a time when there's only going to be probably one customer, one export customer that does their export capacity is greater than their fractionation capacity. And if we get to that time frame, we did not want our liquids to be disadvantage going into the marketplace.

But one thing we have, and we go through this whole process, one thing we have is we have supply. And that's why in this whole 10 years, we've had many, many people come to us both want to help us build an LPG dock or want us to build an LPG dock so they can take it and have an alternative to the incumbents into the marketplace. So as we did that, we found the right opportunity with MPLX to be able to execute that, be able to go forward. So now we can control our destiny.

We got customers that want to control their destiny from the wellhead to water, and we want to control our destiny from the wellhead to the water to make sure that our product can be able to clear. But with the MPLX dock that we have a low capital -- lower capital because it's a brownfield dock. It's very close to Mont Belvieu. So our pipeline capital out there is low as well. And then also, it's very close to open water, which we are getting premium pricing for that to be able to go forward. We saw that opportunity, we jumped on it. We thought this is something that we can use and we can compete in the marketplace, and we've been showing that we're able to do that.

Tremendous amount of people come in very interested in the capacity across that dock. We're working, it comes up in '28. We're working through a lot of things right now to finish contracting that. But as I mentioned on the call, we're very -- we are very satisfied where we are on that contracting journey as we continue to go forward on that. And like I said, we're able to get our customers, they see and value that superior location close to open water.

Something about the Permian...

So the Permian, we think overall, Pierce mentioned, we think here for a period of time, the United States is going to stay in the approximate range of 13.5 million barrels a day of crude oil. But not every basin is going to be the same. The basin that will grow the most will be the Permian. That's where we see most of the growth is continuing to come on. So with that growth, obviously, you're going to get more gas. coming out. We're seeing the Delaware even gassier as they drill out in that area, even more gas coming out. With that increased gas is increased liquids, you're going to get a lot more liquids coming out of the Permian.

So the Permian is going to -- we continue to think it's going to be strong as we continue to -- if you listen to a lot of the producers, if they have a Permian presence, they're going to favor that Permian presence more than some of the other areas. That's where they're going to put, not all, but some -- most of their drilling budget is going to be in that area. So we continue to see that growth in the Permian. And you're seeing as we see more natural gas pipelines being built, more NGL pipelines being built, everybody is kind of seeing that more fractionators being built. A lot of that's being driven out of the Permian. I said the Bakken, we're going to see a little bit of growth. Mid-Continent, we're excited about, but you're talking about a much smaller basin than you're thinking about the Permian.

There's 2 market indicators there, I think, out there, that One is even this week, I think the prices of Waha went negative, maybe down into the $6 range. So that's an indication of a pretty severe tight capacity out of the basin. So any kind of maintenance or any kind of upsets, then it goes negative almost immediately. So that's one of the market indicators.

And the other one is just talking in terms of the pipes that we're going to be involved in, which is the Eiger pipeline, started out about 2.4 Bcf of capacity that we've recently announced, had enough interest in that pipeline to expand it to 3.5 Bcf. You got at least 10 Bcf that needs to get down to the LNG facility. So you got way more demand down there capacity-wise of the LNG than what we have today.

And so the market is saying we're going to build -- we're going to back these pipelines coming out of this because we're not -- we wouldn't be going down this road to expand these capacities just because you got to have contracts behind them, and there are. So I think the market is saying, I'm willing to step up and take capacity on these pipelines, both the LNG side of it and the producer side. So -- and then the fact that you've got those lower prices tells you that the market is really tight out there on capacity. So it's going to grow.

Could you just describe the industrial logic of taking part ownership of pipelines where you don't -- where you're not necessarily the operator?

So the Eiger pipeline is a subsidiary of the Matterhorn pipeline. And so the Matterhorn Pipeline was a pipeline that EnLink invested in. So this is what gave us the opportunity. But the industrial logic behind this is that we have -- we control gas coming off of our gas plants today. And that we need to put them into the market, and we want to make sure that we can get our producers a good netback on their prices. So it was better for us to go in there and buy that capacity, help these projects being built on the Matterhorn pipeline, we did take out capacity. And so that's what's going to be.

When the Eiger Pipeline project came to us, we looked at is looked at as an investment. We like the thesis of that you're going to need more pipeline capacity, natural gas pipeline capacity coming out of the Mid-Continent. We looked at who they had contracted, where they're going and how it was going to be done and because of we are already going to have some ownership in it due to the Matterhorn ownership that we had. So it made sense for us as we look at the economics. And now that it's been expanded, it looks even better for us on an economic standpoint. It's going to be a really nice project for us.

And if we didn't have the capacity, we'd be experiencing that negative $6 range for our producers. So because we have that capacity, we can give them a much better netback than what you have if you didn't have it. So -- and it goes back to what I said earlier, which is we want to touch basically as many molecules as we can, which includes methane as often as we can for as long as we can. So those pipelines go a long way between Waha and the Gulf Coast.

In the last earnings season, one of your competitors on their earnings call mentioned they were looking at maybe repurposing an NGL pipeline leaving the Permian into a nat gas line. And they painted kind of a tough environment for recontracting NGL lines. And just curious your guys' reaction, what you're seeing out there and how you expect things to play out.

Yes. My assessment is that particular NGL pipeline was moving product from -- basically from one customer and that customer is coming up on to contract and decided to go a different way. So they were losing a substantial amount of the volume. So you all of a sudden, you -- I got a whole, think that's a 24-inch pipeline that's 600,000 barrels a day of NGL, all of a sudden, you're going to lose at one swap. It makes sense for them to take it over into the natural gas system, which helps frankly, tighten it up. We've expanded the West Texas NGL pipeline to 740,000 barrels a day. When we did that, it was contracted at a nice return, but we also had a lot of upside or capacity that wasn't contracted. Because of how we went about building that pipeline a little bit or the looping, we looped it a little bit out of time until we had the loop remaining.

And so we have a lot of what we almost think about free capacity on that pipeline. So right now, we think we are in a very good position, and we've proven it that we can contract that capacity based on the fact that we have bringing the Medford fractionator on at a certain time, we'll have frac capacity, and we have pipeline capacity going on as well. And then we continue to grow our G&P to fill part of that capacity along with being able to get third-party processing plants in the area.

So I think we've been able to compete. Yes, is the Permian the most competitive basin out there, not only for natural gas, for G&P, for crude, for all that? Yes, it's the most competitive basin, but it's the one growing the fastest as well. So we still -- the other thing you got to think about NGLs is NGLs is not just a pipeline. You got to have a pipeline, you got to have a frac. You got to have the whole value chain really to compete for that. So just because one portion of it gets a little overbuilt, maybe in the gas pipeline, that doesn't mean the other portions are. They're still seeing a lot of fractionators being built down during the period of time.

So we're still -- and they're being put in. These are greenfield projects. So the TNF that has to support those projects is at a higher level right now. So we think we compete and have been able to compete very favorably in the Permian and be able to continue to bring more volume to our system.

All right. I think we are basically at time. So thank you all very much. Appreciate it.

Thank you, Michael.

All right. This is the session for ONEOK. You've got to my left, Sheridan Swords, EVP, Chief Commercial Officer. We've got Pierce Norton, President and CEO; and Walt Hulse, EVP and Chief Financial Officer. So thank you, gentlemen, for joining me. Appreciate it.

Thank you, Mike.

Welcome. This is open Q&A, so feel free to just raise your hand and any time during the session, and someone will come over with the mic and you can ask your question.

So maybe I'll start. Yes, I guess I'd start just high level over the last few years. You've made some pretty significant strategic shifts in the company, diversifying your Bakken concentration, adding more basins, refined products, crude, NGLs, reducing your gas -- natural gas exposure. Maybe you could just talk through that strategic shift you've undergone at a high level? Do you like where the company is now from a mix of assets, markets, cash flow stability? And is this kind of what you're aiming to get to?

Okay. So I'll take that question, Michael. I'd probably start out by saying that in 2021, in the middle of the year, we had decided as a management team that we did need to take a strong look and really assess our competitive advantage. And so I'll kind of tick these -- you mentioned we've done several acquisitions, which is true and some very large ones. But I'd start with Magellan.

So what Magellan brought to us was what we call demand pull, where we primarily had producers that was a supply push, and we wanted to get into a demand pull kind of situation. So that's one of the things that it gives us because we got much larger in the refined products business with jet fuel, diesel and gasoline distribution. So that's the -- and it also brought to us cash flow stability, brought to us the ability to sustain the earnings with minimum capital, although we have found ways to enhance and extend some of the systems that we had -- that Magellan had.

Then the next one was EnLink. EnLink got us more into the Permian. And if you'll notice, there's a certain order that we went to this. We -- and then we had Medallion, which actually got us into the crude gathering business and was able to connect up to our long-haul pipes that we got from Magellan. So we would have never done Medallion had we not done Magellan first. The EnLink stuff, all of those assets were pretty much on islands. Our assets connected all those. So the whole thing really flowed into our strategy. We want to touch as many molecules as we can for basically as many times as we can for as long as we can. So that's our -- that's the premise of our strategy.

You did mention one thing I want to address, though, you mentioned us kind of reducing our exposure to natural gas. That is true on the interstate side. And there was a strategic rationale for that because those -- it didn't fit with our molecule strategy. It was isolated. We could only touch those molecules one time. The company we sold them to, they had many more options to do connect to storage and already connected some of their other assets. So it would be more valuable to them than it was to us.

So we did divest of that, but we have actually grown the intrastate side of our business through EnLink and also in the storage side of our business. So we've gotten much bigger on the intrastate side, which is really where we like to be because of the connectivity and then the molecule story strategy.

So I guess with all this M&A activity, I think one of the hardest things for investors and us to really get a good grasp on is the synergies. I think you've outlined $700 million to $1.1 billion of synergies across all this. Can you just make us -- maybe just walk us through the major categories of synergies, how far along you are to achieving those? And when you expect to have all those synergies complete and reflected in EBITDA, if there ever is an end to this?

Sure. Well, I think what -- where I would go with that is to start again at Magellan and kind of walk through sequentially. The Magellan acquisition from a synergy standpoint has far exceeded our expectations. I think we've probably been able to capture 80% of what we thought was there and then found a whole lot more than we had expected.

And the reason I think that we found so much more was that they really had limited the capital that they put into the business to about $100 million a year. And effectively, that kind of shut down the organization for looking for opportunities. So there are a lot of real small opportunities where we'd spend $10 million and get $8 million of EBITDA. We have one we spent $12 million, and we're getting $30 million of EBITDA.

So some really nice, very high-return projects, but they fall into buckets. The first ones we get are the easy G&A, you can kind of knock those off. Sometimes they take up to a year to get them because of contractual types of things. But for example, insurance. We've been able to fold some of these operations into our insurance and completely eliminate the cost that had been there before.

And then the next is things like I just mentioned, the smaller capital projects, quick hits, connects the things you can do. And those have been coming in line, and you'll see -- you've seen them so far, and you'll see them again when we put out the fourth quarter in the refined products business.

And then the last bucket is the biggest bucket, and that we like because we have total control over and have had total control over all these synergies with Magellan is that there were some big connections that we had to make to really interplay our NGL system down in Mont Belvieu with the Houston distribution of both refined products and crude that Magellan had. And to accelerate that process, we bought a small little pipeline company called Easton. It kind of -- we were already a customer on Easton. It accelerated by about a year our ability to connect Mont Belvieu to those other Magellan properties. That has just completed. Those connections were just completed here in the third quarter. So we're now starting to see the benefits of that last wave of synergies where we had to spend some meaningful amounts of capital.

We did the same thing up in the Mid-Continent. We're not quite done there yet. We're just in the process, but where we've connected our Kansas NGL network to the distributions across the Mid-Continent and into Cushing with Magellan. So we're way ahead of where we expected to be with Magellan.

Medallion, that was kind of a plug and play. Most of the synergies that we got there, again, were within our control, but really came around our ability to operate those assets in a way that Medallion couldn't because they just didn't have the balance sheet. They had to really let third-party marketers come into their system to handle product. We've been able to remove the third parties and be able to go directly to the customers and then fill our pipes, which is another synergy that's within our control.

And then EnLink, we're just now -- we're about 9 months, 10 months into it. Coming along, the corporate synergies are just about all falling to the bottom line. You're starting to see some of the contractual synergies over the next couple of years that will fall in, and those are primarily NGLs that will roll off contracts from other pipes and then fall on to our system.

So we feel -- and we've got a slide in our deck that we're ahead of schedule as it relates to synergies and that what we really have tried to do is make sure that the vast majority of those are within our control and ones that we aren't waiting for a customer to do something where we do have some of that contractual stuff, but we're right on path.

Great. Maybe we turn to the macro a little bit. Maybe just get your general thoughts as we head here into 2026 and maybe specifically drill down a little bit on the Bakken and the Rockies in terms of the volume outlook in the remainder of this year and then more importantly, into '26.

Okay. So I'll let Sheridan take the Bakken question, but just the macro level view of what we have, Michael, is that there is going to be about 13.5 million barrels of oil that's produced here in the United States. And most of that gets consumed locally and what doesn't goes across the water.

I think the LNG picture that's developing around the Gulf Coast. You heard the term 30-at-30, which is 30 Bcf a day of capacity coming out of the Gulf Coast area by 2030. That's a significant amount. It's almost double what we have currently. That gas has got to come from somewhere, and it's probably going to come from the Permian and the Haynesville, at least in the near term until something could potentially get done out of the Appalachian area. But that is significant.

And then you add on top of that, the AI data centers and the electricity because speed to market is what they're really looking for. And so they're locating these data centers in and around where the producing areas are. It's going to give opportunities for multiple pipelines. In our opinion, you're not going to see any large -- unless you went into spending capital for the electric generation piece of this, you're not going to spend a lot of capital on the pipeline side because they're locating them at or near several pipelines because they don't even want just one pipeline servicing these areas. They'd like to have multiple. So they have backup because of the reliability issues. So I think that's going to be a real driver for natural gas.

And even in a flat crude environment, you're going to see the growth because of the gas-to-oil ratios. So we're going to continue -- and there are areas out there that do have liquids in them that are not necessarily. So you got casing head gas that comes with the oil production, you got your gas well gas that's either dry or your gas gas that's got some liquids with it. So all of those are going to continue to grow, which means just more liquids for us and filling up our assets because we do have the operating leverage both out of the Bakken, out of the West Texas area and with the fractionation that we're putting back in at Medford. So you can answer that.

Yes. Mike, when you think about the Bakken, the Rockies, if you think about the growth out of the Rockies right now, we saw growth from '24 to '25 into the Rockies, and we're going to see growth into '26. The crude oil production, we think, is going to stay relatively flat up there. And with the GOR, you're going to see low single-digit kind of growth on the gas side of that.

The good thing in the Rockies right now, we have capacity up in the Bakken. We have processing capacity. Our capital is going to be lower than you've seen in the past because we've built that operating leverage that we've talked about before that we were able to grow in as we continue to grow. Right now, in the Bakken, we kind of see what happens every year, and we've got to plan on it. It's -- we haven't looked up there, I think it's like minus 9% right now. So it's -- which is normal for them, but we do see heater treaters come on at this time of the year. And so we always see a little bit of dip in our volumes in the fourth quarter and into the first quarter. So nothing unusual right now going on volumes right now.

We continue -- we have talked to a lot of producers up there. The big ones, ConocoPhillips and they are continuing to go forward strong. They're going to drill through this. A lot of the big boys are going to drill ExxonMobil. They're all going to kind of keep their drilling programs that they have going on. We are seeing some private equity in certain areas get a little aggressive at this time because this is their area that they're going to drill. That's all they have. They have this. And there's a lot of areas up there at this crude environment that people can make money at, if this is their one area to grow. So we're going to see them continue to grow some volume out there. So you take that, that's why we think we'll see kind of low single-digit continued growth up there in the Bakken.

Maybe just on the Bakken. So I think Bison Express starting up, I think, Q1 '26. And just curious with the start-up of that gas residue pipe, if that has implications on your ethane recovery as you look out to '26. And if I recall correctly, you usually don't put much in the guidance for ethane recovery. It's more of an upside optionality. But yes, just curious if -- what you think about that.

One of the thing about Bison, we need a little bit more gas. A lot of that's been contracted, continue to go on that. And that comes on. I don't see it having too much of an adverse material impact on that. a lot as you see basically just the difference between having gas up in the Bakken versus Henry Hub, which is really -- when you talk about our discretionary ethane, that's really what we're doing is we're natural gas out of the Bakken to the Henry Hub price because we're buying -- basically buying the ethane off of a natural gas price up there.

So I think that's still going to flex a little bit. But I don't think all of a sudden, you're going to see the Bakken price have substantial move to Henry Hub price and then what you've seen in history.

Maybe back to Pierce's 30-at-30 comment, I like that one. There's been some talk or chatter lately about Mid-Con permits and maybe rigs ramping up to support some of this LNG build-out wave over time. So you guys are a big player in the Mid-Con. So curious if you're -- what you're seeing there or hearing there on that front.

Mike, what we've seen is that as Pierce kind of talked about it, when you have all that demand for gas and you're starting to see gas prices in really nice attractive levels, you're in the high $4 and especially when you see crude at the $60 range, you're seeing a lot of the producers try to go to a more gassier or what we call the condensate window. And the Mid-Continent is prime for that. It has an oil window, it has a condensate window that a little bit of dry gas window. And we are starting to hear producers talk about into 2026 in the Mid-Continent moving more to that condensate window.

Now the condensate window, I mean, the gas is still rich. It's a very rich gas. The thing that we like about it is that IP is at a much higher rate than we see in the oil part of that window, continue to go forward. So that -- we've always felt the Mid-Continent has been kind of our high gas price option that you'll see more volume come on, seeing more of that. And that doesn't take into account. We're still seeing that I've talked about before in the western side of the state, the Cherokee formation that has -- we've got a lot of people very excited about that formation over there, which is still a little bit oilier, but it does get some pretty good gas coming out of there, and they're continuing -- as we've talked to them, they are wanting to continue to drill that out, explore that, expand that as well.

So for a long time, the Mid-Continent, we've kind of called it to be flat and going forward. But now it continues to become more and more exciting for us for increased volume growth out of that. And obviously, we've still got a very nice position on the NGL outlet where we get most of the NGLs coming out of the Mid-Continent. And with our EnLink acquisition, we've more than doubled our G&P presence in there. So all that -- as we continue to grow, we have a wider footprint, we can handle more area.

That was one of the synergies that we had with EnLink is EnLink has a very large contract with one producer that there are certain parts of it, they could not service because they were not close enough and it became uneconomic for them. But when you put the legacy ONEOK system with that expands our reach and now we're able to get some very nice -- not get -- we have that contract. We just don't have to release those acreage. I think so that's been very nice. So we continue to see that growth in the Mid-Continent and pretty excited about it.

And the demand side is actually growing there because after after COVID, we saw a lot of influx of people coming into the Oklahoma area. Oklahoma has always been a net exporter of gas. A lot of people don't realize that even during the dead of winter, like January, February, the Oklahoma area producers have exported around 3 Bcf a day. So the -- and the capacity and the volumes have been larger than where they are today, even though they're growing. So the capacity is there to export the gas from Oklahoma and you just need it on the demand pull side, which that's what the LNG is going to do and the AI data centers.

So maybe if we shift a little bit to 2026. I realize you're not going to give us guidance right here. But if you want to go ahead, but you're probably not. So maybe you could just walk through at a high level, how we should think about what are the drivers of growth in '26 versus '25. How big a factor is volumes versus butane blending spreads? And then within that context, on the third quarter call, you kind of pulled back your 2026 outlook. So can you also just speak to that decision?

Sure. Well, the good news about the growth into '26 is it's really driven by the projects that we've been working on and completing. I had mentioned before the Eastern connections that just finished up in the third quarter. We're going to enjoy those here in the fourth quarter, but we'll get a full year of them going into '26. Those connections that we've made up in the Mid-Continent that we're doing right now in the fourth quarter, we'll get all of those in '26.

We'll bring on the Bison Pipeline, which was mentioned here a second ago, which actually sends gas down to the Cheyenne market. That will come on. That's fully -- that's contracted. So that starts day 1 when it comes with those contracted rates. And then we've got the Denver expansion of our refined products pipeline, which also comes in, in '26. So we have a lot of kind of stair-step items that will fall in that are not reliant on the drill bit.

As we look at '26, one of the reasons you highlighted the spread between butane and RBOB, it's been about at its lows here through most of '25. We've kind of got that marked into our view for '26. So any upside that we get there is -- will fall to the bottom line.

But I think really where we -- why we backed off is as we saw crude go from a $75 price, which is where we were when we started to put that outlook out there to a $60 price, we've just seen producers kind of back off a little bit. They haven't stopped drilling. They still have the same number of rigs. But I kind of use the analogy, they were going 75 miles an hour they're still going fast, but they've kind of backed up and they're going 60 miles an hour now. So just not leaning in quite as much. So on the margin, while we think there's still going to be growth, it's not going to be as robust as we thought it was going to be.

Maybe just also on '26, just as we think about the major capital projects that are on the board? And how do we think about just directionally '26 CapEx versus '25?

Yes, '26, there's quite a few of them that were in the process here on '25, still continue in '26, get wrapped up in '26. I mentioned the Denver pipeline. We get the first phase of the Medford frac done in fourth quarter of '26, and then we get the second phase in early '27. Those are 2 bigger projects that roll off. So we'll start to see that real kind of reduction in CapEx in '27, but '26 is going to be pretty similar to '25.

So maybe just to round out this topic, M&A. You've done a lot as we discussed. Would you say that -- what is your appetite for M&A at this point? Do you feel like you've basically built out what you want to build out? Or do you feel like there are still areas where you'd want to fill in?

Well, I think we always -- back when we got together in '21 and came up with our key criteria that we were looking for, there are several of those things that still exist. Do we -- would we like to have even more free cash flow? Yes. Would we like to have maybe a little bit more scale? Yes. Do we want to continue to diversify? Do we want to expand and extend our existing assets? The answer to all of those is yes. But we're in a position now because of our asset mix and the opportunities we have on synergies that we can be patient about this.

And everything that we know exactly right now what it is that we would like to look at as it relates to M&A. But we don't feel like any of the things that we would be really interested in are necessarily what we would say, well, we got to go get something done today. So we think we can be patient, and we can, again, be intentional and disciplined in what it is we're going to do on the M&A front.

I mean you can see by what we did of doing Magellan and then doing EnLink and then doing Medallion and then the Easton is in there. All of that stuff was very intentional, and we could see how all those pieces came together that fit the puzzle that we have today.

Can you folks describe the wellhead to water strategy and just the competitive landscape as you see it today?

Yes. I mean the wellhead to water strategy is just basically we have customers and everybody else that wants to give us natural gas, go through our processing plants, take their NGLs down the pipeline and be able to move it across the dock to be go forward. We have some producers that want that as well. Also from our side, we look at it is we want to control our complete destiny, meaning that as we get liquids down into the Mont Belvieu area, we want to make sure they clear into the market center.

When we decided that -- we had been looking at the LPG dock for 10 years and trying to understand when do we need to get into it? What's the right time to be able to and what are all the issues. Through all that study, we found there's a couple of things that we wanted. One thing is we wanted something off the Houston Ship Channel, and that's what a lot of our customers wanted us that way. We wanted to have a nice -- be able to have a green -- a brownfield that the cost isn't so much. That's what NPL brought to us as well. But most more, we want to be able to clear our liquids out there.

Our liquids today are already moving across other docks. We're not contracting across other docks, but they are moving across other docks. But we went in and looked at it and looked forward into the future and said there's going to become a time when there's only going to be probably one customer, one export customer that does -- their export capacity is greater than their fractionation capacity. And if we get to that time frame, we did not want our liquids to be disadvantaged going into the marketplace.

But one thing we have and we went through this whole process, one thing we have is we have supply. And that's why in this whole 10 years, we've had many, many people come to us, both want to help us build an LPG dock or want us to build an LPG dock so they can take and have an alternative to the incumbents into the marketplace. So as we did that, we found the right opportunity with MPLX to be able to execute that, be able to go forward. So now we can control our destiny. We've got customers that want to control their destiny from the wellhead to water, and we want to control our destiny from the wellhead to the water to make sure that our product can be able to clear.

But with the MPLX dock that we have a low capital -- lower capital because it's a brownfield dock. It's very close to Mont Belvieu. So our pipeline capital out there is low as as well. And then also, it's very close to open water, which we are getting premium pricing for that to be able to go forward. When we saw that opportunity, we jumped on it. We thought this was something that we can use and we can compete in the marketplace, and we've been able to shown that we're able to do that. Tremendous amount of people come in very interested in the capacity across that dock. We're working -- it comes up in '28. We're working through a lot of things right now to finish contracting that. But as I mentioned on the call, we're very -- we are very satisfied where we are on that contracting journey as we continue to continue to go forward on that. And like I said, we're able to get -- our customers, they see and value that superior location close to open water.

[ Anything about the permian reduction. ]

So the Permian, we think overall, Pierce -- we think here for a period of time, the United States is going to stay in the approximate range of 13.5 million barrels a day of crude oil. But not every basin is going to be the same. The basin that will grow the most will be the Permian. That's where we see most of the growth is continue to come on. So with that growth, obviously, you're going to get more gas coming out. We're seeing the Delaware even gassier as they drill out in that area, even more gas coming out. With that increased gas is increased liquids. You're going to get a lot more liquids coming out of the Permian.

So the Permian is going to -- we continue to think it's going to be strong as we continue to -- if you listen to a lot of the producers, if they have a Permian presence, they're going to favor that Permian presence more than some of the other areas. That's where they're going to put -- not all, but most of their drilling budget is going to be in that area. So we continue to see that growth in the Permian. And you're seeing as we see more natural gas pipelines being built, more NGL pipelines being built, everybody is kind of seeing that more fractionators being built, a lot of that's being driven out of the Permian. I said the Bakken, we're going to see a little bit of growth, Mid-Con that we're excited about, but you're talking about a much smaller basin than you're thinking about the...

There's 2 market indicators there, I think, out there that one is even this week, I think the prices of Waha went negative, maybe down into the $6 range. So that's an indication of a pretty severe tight capacity out of the basin. So any kind of maintenance or any kind of upsets, then it goes negative almost immediately. So that's one of the market indicators.

And the other one is just talking in terms of the pipes that we're going to be involved in, which is the Eiger pipeline, started out about 2.4 Bcf of capacity then we've recently announced, had enough interest in that pipeline to expand it to 3.5 Bcf. You got at least 10 Bcf that needs to get down to the LNG facility. So you got way more demand down there capacity-wise of the LNG than what we have today.

And so the market is saying we're going to build -- we're going to back these pipelines coming out of this because we're not -- we wouldn't be going down this road to expand these capacities just because you got to have contracts behind them, and there are. So I think the market is saying, I'm willing to step up and take capacity on these pipelines, both the LNG side of it and the producer side. So -- and then the fact that you've got those lower prices tells you that the market is really tight out there on capacity. So it's going to grow.

Could you just describe the industrial logic of taking part ownership of pipelines where you don't -- where you're not necessarily the operator?

So the Eiger pipeline is a subsidiary of the Matterhorn pipeline. And so the Matterhorn pipeline is a pipeline that EnLink invested in. So this is what gave us the opportunity. But the industrial logic behind this is that we have -- we control gas coming off of our gas plants today. And then we need to put them into the market, and we want to make sure that we can get our producers a good netback on their prices. So it was better for us to go in there and buy that capacity, help these projects get built on the Matterhorn pipeline, we did take out capacity. And so that's what's going to be [indiscernible].

When the Eiger pipeline project came to us, we looked at it as an investment. We like the thesis of that you're going to need more pipeline capacity, natural gas pipeline capacity coming out of the Mid-Continent. We looked at who they had contracted, where they're going and how it was going to be done and because of we are already going to have some ownership in it due to the Matterhorn ownership that we had, so it made sense for us as we look at the economics. And now that it's been expanded, it looks even better for us on an Eiger standpoint. It's going to be a really nice project for us.

And if we didn't have the capacity, we'd be experiencing that negative $6 range for our producers. So because we have that capacity, we can give them a much better netback than what you have if you didn't have it. So -- and it goes back to what I said earlier, which is we want to touch basically as many molecules as we can, which includes methane as often as we can for as long as we can. So those pipelines go a long way between Waha and the Gulf Coast.

In the last earnings season, one of your competitors on their earnings call mentioned they were looking at maybe repurposing an NGL pipeline leaving the Permian into a nat gas line. And they painted kind of a tough environment for recontracting NGL lines. And just curious your guys' reaction, what you're seeing out there and how you expect things to play out.

Yes. My assessment is that particular NGL pipeline was moving product from -- basically from one customer and that customer is coming up on to contract and decided to go a different way. So they were losing a substantial amount of the volume. So you all of a sudden, you -- I got a whole -- I think that's a 24-inch pipeline that's 600,000 barrels a day of NGLs. All of a sudden, you're going to lose it one swap. It makes sense for them to take it over into the natural gas system, which helps frankly, tighten it up.

We've expanded the West Texas NGL pipeline to 740,000 barrels a day. And when we did that, it was contracted at a nice return, but we also had a lot of upside or capacity that wasn't contracted because of how we went about building that pipeline a little bit or the looping. We looped it a little bit out of time until we had the loop remaining. And so we have a lot of what we almost think about free capacity on that pipeline.

So right now, we think we are in a very good position, and we've proven that we can contract that capacity based on the fact that we have bringing the Medford fractionator on at a certain time, we'll have frac capacity, and we have pipeline capacity going on as well. And then we continue to grow our G&P to fill part of that capacity along with being able to get third-party processing plants in the area. So I think we've been able to compete. Yes. Is the Permian the most competitive basin out there, not only for natural gas, for G&P, for crude, for all that? Yes, it's the most competitive basin, but it's the one growing the fastest as well.

So we still -- the other thing you got to think about NGLs is NGLs is not just a pipeline. You got to have a pipeline, you got to have a frac. You got to have the whole value chain really to compete for that. So just because one portion of it gets a little overbuilt, maybe in the gas pipeline, that doesn't mean the other portions are. They're still seeing a lot of fractionators being built down during the period of time.

So we're still -- and they're being put in. These are greenfield projects. So the TNF that has to support those projects is at a higher level right now. So we think we compete and have been able to compete very favorably in the Permian and be able to continue to bring more volume to our system.

All right. I think we are basically at time. So thank you all very much. Appreciate it.

Thank you, Mike.

Thanks, Michael.

Hi, everyone. So we -- I think we knew that there would probably be some casualties from the travel delays. And so unfortunately, ONEOK had some travel issues today, but they will be joining us virtually. And I think it's all going to work out.

We'll have Pierce Norton, President and CEO; Walt Hulse, EVP and CFO; and Sheridan Swords, EVP and CCO, joining us. And let's see if they come up on the screen. Oh my gosh. Hi guys. Can you hear me?

We can.

I can see you here, too. This is so much better than my office. Great. Well, thank you guys so much for joining us virtually today. I'm super excited about the ONEOK story.

Great. Thank you...

So yes, we can have a room of people that are kind of having lunch. And so we can kind of just jump right into some questions.

So I think just as an opening question, your portfolio has changed a lot over the last 3 years with some of the acquisitions that you've pursued. Can you talk about the original rationale for some of the major transactions? And do you feel like the W portfolio today in terms of asset mix is close to your ideal end state?

So Jean, I'll take that question. First of all, thank you for inviting us to your conference and allowing us to come and talk to you today and the others. I do apologize for our travel issues that sometimes things can't get off. I think it shows how innovative our industry is to be able to pivot and do something like this on the fly. So thank you.

So your question, -- we -- back in 2021, we were visiting with the Board, and we believe that we had 5 key areas that we needed to address in the company. The first one being diversity and not only diversity in different basins, but diversity maybe in our business mix and to extend the value chain of the company. So that was the first criteria we were looking for.

The second was a combination of things, which was the cash flow stability of whoever that we would buy, along with the capital intensity of that company. So could we find something that had good cash flow stability that could be sustained with very little capital applied to it going in the future.

And then the third thing was what would the market position be of this company that we bought? Is it -- does it have a competitive advantage in the areas that they're in?

And then the fourth one was scale. We wanted something that would be meaningful, that would be a growth platform that which is kind of project us kind of into that next level of market cap of our business.

And then the last thing was synergies. And oftentimes, when you do a merger or acquisition, you're depending on synergies that somebody else would basically come through for you. We wanted synergies that we controlled.

And so that was kind of the -- those 5 criteria for what we were looking for, and then we kind of put these different companies through that. And as you know, Magellan is the one that kind of bubbled up to the top. And that set us up to actually pivot and do some more gathering and processing. We did Medallion. We -- that interconnected with our long-haul pipes. So that's kind of the story behind how we got to where we are today, but it was very intentional. It wasn't just responding to somebody coming in and saying, well, we would sell this to year 1. It was intentional for us to go out and find these particular things that met those 5 criteria.

That makes sense. And I think if you're looking forward, are you pretty happy with where the mix is? Or would you say that, that criteria would still be kind of how you're evaluating potential future state?

I mean I will say that some of those things have dropped off. They're not quite as important. It's like we don't necessarily feel like that we need to be only looking for scale. So we actually revisit this criteria. Every time we do some sort of an M&A activity, we go back to the Board and say, which ones apply and which ones don't and which ones should we add. So we dropped a few, added a few. But I'd say, in general, we're very pleased. And we're in a position where we think we can expand and extend what the asset footprint that we have in all of our businesses.

Makes sense. Looking at where ONEOK has traded this year, what do you think the market is missing or underappreciating about the story?

Jean Ann, I'll take that. I think that realistically, we put 3 companies of size with a couple of other small add-ons to that. So a total of 5 companies together in about an 18-month window. And the last one just came into the fold here in February being EnLink. I don't think the market has seen a clear picture of how all of those companies together produce EBITDA going forward. So this year is kind of that test year as we bring EnLink into the fold and start to capture synergies there, continue to capture the synergies that we've had from Magellan, which have exceeded our expectations.

And so delivering on the quarters like we did here just invest in the third quarter and showing the true earnings power of the company going forward, I think, is really just something that's a wait and see, see where we're going to go and looking for a catalyst. And I think that catalyst is really seeing us deliver on those earnings.

Yes. I think that makes sense. That's a great segue to my next question. You show a slide that there could be $700 million to $1.1 billion of synergies from the deals. Can you describe the major buckets of these synergies and how that number is trending versus your original expectation?

Sure. Well, I mean, right off the bat for both Magellan and EnLink, there were clearly kind of those G&A synergies that come pretty quickly. Some of them stage in over the course of the first year or so, depending on contract roll-off and things like that. In each case, that's probably $75 million to $100 million. So those have been done. They're in. Some of the examples of those would be insurance savings. We effectively rolled EnLink into our insurance program at 0 cost. They were paying tens of millions of dollars for the insurance that they had.

And then your normal G&A. But the exciting ones are the commercial opportunities. And when we got into Magellan, we had an expectation of where we thought we could really deliver on synergies. Most of those came to fruition. But what's been exciting is the opportunities that have developed since then. I think as we got into Magellan, we realized that it had been starved for capital a little bit. And so with that happening, quite a few of the smaller projects just weren't bubbling up to senior management, and they weren't getting done.

And so when we came in and took a fresh look at everything, there was this excitement that was developing within the legacy Magellan workforce, and they've showed up with all kinds of different projects that were incredibly high returns. So -- we like to use an example of one where we had to spend $10 million out in El Paso and got an $8 million annual return on it. So clearly, we'll do 80% projects all day long.

As we came into Medallion, again, that was a business that was really set up to feed and fill our 2 long-haul crude pipes, and there have been some nice synergies there volumetrically being able to use our balance sheet to bring product on to the pipes that Medallion just wasn't in a position to do. And then as we bring on EnLink, and I would say we're still in the early stages of those, those are in line with our expectations. Some of those were clear contracts that had to roll off and those new volumes just roll right over on to our NGL system, particularly in the Permian because we pretty much already handled all of their NGLs in the Mid-Continent.

But we had pretty significant overlap in the Mid-Continent in our G&P business. Significant synergies are just now starting to develop on that. And I think that what we've really seen and we didn't expect was more opportunities than we expected on the natural gas side of EnLink. There were things that we could do and that they weren't necessarily taking advantage of. And then clearly, the last is rolling their NGL assets, just specifically the fracs into our full network of fracs and being able to optimize across 3 different locations has seen a real nice benefit.

When you look at back at the Magellan business, our blending opportunities have exceeded our expectations. Volumetrically, we're up very significantly, about 15% year-over-year. Unfortunately, the spreads have collapsed in that so that -- we're kind of net neutral there, but we're in a position that as those spreads come back that we will see a pretty meaningful uplift there. And those -- the ability to blend has really been extending out on the system, having product where it needed to be to blend. We've taken logistics costs out of the Magellan business where they were trucking blend stock out to various locations.

We've been able to get it either on our NGL pipes or put it on the refined products pipes. And that's allowed us to reduce logistics around blending about $0.10 a gallon, which is pretty meaningful. And then it's allowed us with that lower cost to blend in more places further out onto the system. So we're excited about the opportunities. We continue to find new ones every day. And I think the best thing is that the vast majority, and I really mean the vast majority of them are within our control. They're not dependent. They're not supply push type of synergies. So as we are able to bring them on, they drop immediately to the bottom line. And in most cases, they're very small capital amounts.

That makes sense. And you would expect the $0.10 per gallon improvement to kind of roll in over 2026?

Yes, exactly. That was really -- some of it was around the Easton acquisition that we did that connected Mont Belvieu to the East Houston and Galena Park areas. A bunch of it is in the Mid-Continent, where we are connecting our Conway fracs into the refined products system in the Mid-Continent. That is just being completed here in the fourth quarter. The connections down at Easton were finished in the third quarter. So we're starting to see a little bit of Easton and all of it will be coming in here as we get into the -- into '26.

That's great. So kind of talking more about 2026, ONEOK's 2026 outlook has come down a little bit year-to-date. Can you kind of talk about how much of that is from commodity spreads coming in, so the butane blending that we're just talking about, for example, versus a lower production growth outlook?

Sure. The commodity, specifically around the butane blending and some of our other spread businesses, a couple of hundred million, $200 million or so of impact that we saw with lower spreads. Put that in the context of our overall company, it's around 2% of our EBITDA. So not a huge amount. It falls in that spray. We still are a volume times rate company. 90% of our business is fee-based. About 5% is differential, either location or timing and about 5% is commodity. So that was that portion. And then the balance is really as we've seen crude prices go from the mid-70s down, I think, today into the high 50s. We continue to see nice activity out of our producers, but they haven't been leaning in quite as much as they've been kind of taking their time a little bit.

And I use the analogy, they were going 75 miles an hour. Now they're going 58. They're still going fast, but they're not going quite as fast as they were before. And we need to get a sense of where they're going to be in '26. They're going through that process right now. If crude stays right around here, I think we're going to see most of the producers not change up what they're doing at all. They're kind of making sure that it's not going to drop into the 50s or lower, lower 50s and where they might have a little bit of a backup. But that's the other component that we're just trying to get our hands around. When we do, we'll roll that out here in -- with our '26 guidance right around the first of the year, just after the first of the year type of thing.

That's super helpful. Kind of when are you targeting to reach your long-term debt-to-EBITDA target of 3.5x EBITDA? And how do you think about capital allocation after that?

You hit me right and left here. We got to get Sheridan to answer a question here...

We're going to get to operations...

All right. We're on target to head to that -- we said 3.6x in '26. I think it's important for us to put out there that the 3.5x target is a self-imposed target. Moody's wants us to be at 4x or below for Baa2 and S&P wants us at 3.75x. We still think 3.5x is the right place to run the business over the long term, and that's going to continue to be our target.

But frankly, with the stock down here at these levels, we are thinking more about should we slow that down a little bit and maybe think about allocating some capital to shareholder return as well. So we're clearly getting through both of the agencies' targets headed towards our 3.5x. But I think we have a little more flexibility and are kind of thinking about that capital allocation.

Makes sense. Are you hearing from investors that they want more growth or more free cash flow? Or it just depends on which investor you're talking to?

I think it's all of the above. It definitely depends on the investors. But I think probably one of the keys to that is that they want to make sure that we aren't chasing growth and that we're using discipline to make sure that we continue to get the high-return projects that ONEOK has been known for in the past. And we are trying to be disciplined there and make sure that we do only pursue projects that are getting the return on invested capital that we're used to because we have the opportunity to return cash flow to shareholders as well. So we're trying to work that balance. We always want to grow the business and do it with good capital projects, but we are going to make sure that we're disciplined and not chase projects just to try to get growth at what are returns that wouldn't really be commensurate with the risk that you'd be taking.

Makes sense. Great. I think with that, Sheridan, maybe we'll move over to operations and commercial questions. In most basins that you operate in, you should have significant operating leverage. I think you have spare processing transport and frac capacity all over. So would you agree with that? And can you kind of speak to the advantages that, that could provide you going forward?

Yes, Jean. Yes, I would agree in a lot of areas, we have that operating leverage, and that was by design. When we had our big build-out and building the backbone of our business, we found through time that it's a lot easier to add just a little bit more steel, a little bit bigger piece of pipe when you're putting in the ground, very capital efficient to add quite a bit more capacity onto the system. So that's what we did. Really, if you put a couple more inches on a piece of pipe, you're really just buying a little bit more steel as you put it into the ground. So that has been our philosophy for a long period of time.

So now where we sit, we have plenty of capacity coming out of the Bakken. We have plenty of capacity coming out of the Permian that we can grow into. And really, as we look forward, that means that we're not going to have to spend near the capital that you typically would see as we continue to grow volumes out of these areas. The frac is the same thing. With Medford coming on, we will have excess frac capacity. We don't have that today, but we will when Medford comes on, we'll have excess frac capacity that we will be able to grow into, especially as we see volumes coming on in the Permian.

It's in one area, and we're alleviating that we don't have that operating leverage is our processing capacity in the Permian. But we have over 500 million a day of processing capacity coming online here through 2026 that will give us some more operating leverage in that area, so we can be able to be there when the producers need them and be able to fill the long-haul NGL pipes from there.

Makes sense. I was going to follow-up, I guess, on the Permian. I think one common investor concern is that there appears to be more than enough NGL capacity in the Permian. Can you kind of discuss your exposure? And would you feel that you need to backfill with more processing capacity like significantly more, either organically or inorganically to match that up?

Well, we're really going to look at as we grow our processing capacity out there, we want to first do it. We really like to do it organically. That's kind of the whole reason we bought the EnLink to be able to grow that asset. And you're already seeing we're having quite a bit of success as we -- as I mentioned before, we bring on this 500 million a day of processing capacity. But also in terms of the NGLs, we also will be -- have the benefit in '26 and '27 their EnLink had some contracts with other non-ONEOK NGL service providers. As those contracts come off, that volume will automatically come over to our system. The other thing is we built -- we built this additional operating leverage on our system. We still have great projects when we do it. So we don't need to fill our pipelines to have a great project. So we're not going to just chase volume and at lower and lower prices just to fill the system. We already have good projects, and this is just really making them actually substantially better as we put more volume to the system.

That makes sense. Is there any update on how the contracting for the LPG export terminal is coming along? And can you walk us through the competitive dynamics there?

Yes. I mean we are very pleased where that contracting is going, and I mentioned that in the call. It continues to progress at a level that we are very happy with right now. We have a lot of interest in from people wanting to sign up for capacity. And the big competitive advantage is really the location. We do have a superior location and the customers and the people we're talking to, they see that. They understand they value that closeness to the open water where you take a lot of the risk out of that from fog and demerge and some of those things. So we are very pleased where we are right now. It's going to be a very nice project.

Makes sense. Has the recent start-up of third-party ethane export terminals over the last quarter or 2, has that created pull-through for more ethane recovery in the basins that you're in? And do you expect that to continue?

Yes. I mean we saw it almost pretty immediately that the frac spread on ethane widened out when those facilities come online. And that really allowed us to -- in our discretionary ethane business out of the Bakken to get wider spreads and see a little bit more coming out of the Mid-Continent. And we do see some recovery out of there as well. We do some discretionary ethane coming out of the Mid-Continent as well.

Obviously, the Permian has been in recovery and it's going to stay in recovery, especially now when we see that Waha prices are negative. It's obviously going to be the first one that comes out. But there was a definite move in the market when we saw these export terminals come online, and that's very good for us.

Was there actually like a lot of ethane that wasn't already being recovered in the Permian, I guess, that you think happened, I guess, after the Waha prices went negative that would have impacted how much was coming from Mid-Con and Bakken...

Well, no, I mean, I can really just speak to our system and what we see on that. We saw a pretty good ethane recovery coming across that system, what you would see for a full ethane recovery. Obviously, every plant, you got older plants and newer plants and as volume moves around, you can get a little bit more ethane here and there out of the Permian. But for the most part, it's been in full ethane recovery for a period of time.

But as this new volume came on, it did kind of widen the spreads a little bit. We brought more volume out of the Bakken because of that, and we're able to bring a little bit more out of the Mid-Continent. We still, at times, see the Mid-Continent, as I've said before, being kind of in and out. It did give us an opportunity to bring some more with discretionary ethane as we went in there and worked with both our G&P and other third parties on coming to a number that they could bring some more volume.

Makes sense. I think another common question about the company is that you have had kind of a dominant position in the Bakken for really a long time. And next year, there will be a competing pipeline coming in. How do you view the sort of risk there, the amount of market share that you lose?

Well, I'd first start off as we talk about it, we talk about the market share up there on the NGL side is our G&P has 60% of the market share on the G&P side. So that volume is not at risk. That's always going to stay up. So now we start talking about what's left of the 40% that is not coming through our G&P assets. And -- most of that is all contracted very long term. And I'd say most of that, there is a contract that's coming off here in 2026. That is a Kinder Morgan plant that will go into DH. We know that we're going to lose about 20,000 barrels a day on that pipeline in the South. But also that pipeline, once it gets to Guernsey, it's going to go into another pipeline that we know that only has capacity of 20,000 barrels a day.

So if they want to get any more than 20,000 barrels a day, more capital has to be spent, and they have to lay at least probably 200 miles through some very rough area to be on the front range up from a political standpoint to be able to get in there and to go forward. But we think we have a very competitive position out there, be able to dual lines, a lot of redundancy, a lot of resiliency in our system that we can make sure that the producer volume stays online, both from a gas and an NGL perspective. And that's really what the producers want. They want to make sure that their oil is going to flow.

Yes, Jean, the one thing I'd add to that is, I mean, we're really selling reliability. in a one-stop shop that if you put a molecule on our gathering and processing, it's going to end up down in Mont Belvieu. And the same thing if somebody else processes it, it's going to go on the NGL system and end up being in the Mid-Continent or Mont Belvieu too. So that's what we're emphasizing with the producers and the reliability of all of our systems up there because if that stuff doesn't flow, it really impacts their economics, not really on the NGL and the gas side, but on the crude side.

That makes sense. How do you think about gas-to-oil ratio growth in the Bakken and the Permian? If oil growth is a little slower next year than in the past, how do you think that, that would affect gas-to-oil ratio growth?

Well, when we think about gas-to-oil ratio, I start off with that we know that when a well is drilled and starts producing, the gas-to-oil ratio grows on that well is it mature. When you look from a basin-wide standpoint, what really caused a lot of the fluctuation in gas-to-oil ratio was a little bit down is if there's a lot of new production coming in at a lower gas-to-oil ratio, it will still grow over time. But if you got a lot of new production coming in, you'll see -- you can see the basin-wide GORs come down a little bit. So obviously, if you have a slower growth, that's going to tend to be to a faster-growing GOR in the basins as we go forward. So we definitely think if growth slows down, the growth in the gas will be -- will not slow down commensurate with the slowdown in crude oil.

Makes sense. And I guess what you're kind of describing is sort of what happened in the Bakken where people moved to areas where there was just less gas than the starting wells. I guess it seems like that's unlikely to happen in the Permian, but if you can just kind of talk a little more about your outlook there.

Well, I'll give you a little bit on -- and what happens I'm kind of explaining in with new production. In the Bakken, we have some areas that the GOR is 6 and 7, and then we have new production that's coming on at 1. Now that one will grow, just like it did where those 6 and 7 are at a period of time. So even in the Permian, as they drill, those wells will grow in GOR specifically. Now will the basin grow in GOR? It all depends what I'm saying on those new wells coming in. But obviously, if they drill less wells, less new wells, then the old -- the more mature wells will have a bigger impact on the overall basin average is what I'm saying as we continue...

Yes. Okay. No, that makes sense. So kind of switching gears, can you provide any update on how the Arizona refined product pipeline open season is coming along? And what are the competitive advantages of your pipeline versus competing projects?

Yes. So the open season is still going on right now. I mean, obviously, we came out with our open season then subsequent, there was another open season that came online. We did extend our open season. We've had a lot of interest in it, but there's a couple of people who want to continue to look at this other option as they go forward. So we've extended it out to December 5. And so we give some of our customers a little bit more time to evaluate this. We -- but we have had very good response so far from the market, especially from the demand side in Phoenix. There's very a lot of interest on that.

Our big advantage as we think about it, as we look at the competing project is our access to the Gulf Coast. And the Gulf Coast is the area that's long refined products. They need to export refined products. The Mid-Continent is a fairly balanced pad that there's enough demand in that area for the amount that's being produced. And so a lot of people are looking to clear out of the Gulf Coast. So we've definitely seen that as advantage on our system and a lot of our customers are expressing that to us.

Makes sense. Is there any concern around longevity of demand for that post 2040 for the products? I think you could get like a 10-year contract. And there's obviously like a huge gap in terms of California supply-demand, I think, over the next 5 years, probably even 10 years, but it seems like after 2040, it's kind of hard to say.

Yes. I mean if you think about the supply/demand, we're really thinking about Phoenix. We're already -- Phoenix is already today being supplied by some barrels coming out of California. So we're seeing some rationalization of refineries in California. So obviously, that's going to pull back -- has a potential to pull back refined products going into Phoenix. And also, Phoenix has grown from a population standpoint. So as we look further out, we still see a good strong demand into the Phoenix market with the rationalization of supply coming in there and a lot of people moving into the areas.

We've done our supply and demand analysis. We like what we see out there, and we're a demand pull. This system is demand pull. So we want to be tied in where we continue to see growing demand. We have not seen a substantial amount of EV penetration into the Phoenix market. as we've seen maybe more in California. And that gives us a lot of comfort being able to do a project like this and gives us a lot of comfort to our customers. And the other thing we're also seeing is not just from -- it's not just unleaded or gasoline that we're shipping out there.

We're seeing pretty good demand for jet fuel. And jet fuel, we're seeing that demand grow across our footprint very nicely as we continue to see more gates being put on airports. Obviously, that's one of the backing of our Denver expansion project that will be coming on halfway through 2026. And we see more demand for jet fuel into the Phoenix market as well. So it's not just all more cars and population from those cars, but also population move into the area I wanted to travel.

Makes sense. And maybe just one more actually on the refined products pipeline since that's kind of a new part of the footprint. I guess how do you think about -- how would you kind of recommend people think about modeling that kind of like flat volume, but I believe you are able to get inflation growth on that, which I think a lot of people sometimes miss, but anything that you can kind of offer on how you think about that asset?

Yes. We think of that asset and one of the reason it's a very stable asset. We -- obviously, we have our synergy projects that we're talking about that bringing on that will give us a bump, a pretty good bump in there. And we do have these growth projects, the Denver expansion is going to be clearly an additive to what was in there. The -- we've done some expansions into El Paso.

That was coming on about the time we got Magellan, and we've even gone after subsequent open season that was fully subscribed. -- going out to El Paso. So we see that very steady in these growth projects bringing a little bit on. But long term, we don't see a tremendous amount of capital being spent in this, but a very resilient, nice cash flow machine on the refined products.

Makes sense. So moving over to the Mid-Con. There's been a lot of buzz about Mid-Con permits and maybe rigs ramping up to support the LNG build-out wave that, that could be kind of the basin behind the Haynesville. That would obviously be very beneficial to you. So anything that you're seeing in the Mid-Con?

Well, I'd tell you, as we talk to our producer customers out there, they've definitely said if gas prices stay at these levels and oil prices stay low, they definitely have a potential to shift a little bit more of the gassier area of the Mid-Con. And when I say gassier, it's still a very liquid-rich part of the Mid-Continent. It's not dry as the Haynesville is dry that it's ready to be put into the natural gas pipelines. But what we do see, if they do shift over to a little bit more gassier area, especially of the STACK that the wells come in at a much higher IP on the gas side, and we'll see a lot of growth for us on the gas side.

So it seems to be lining up that we may see some really good growth into the Mid-Continent. I've always said that our Mid-Continent business was almost kind of like a gas option. If you got into a market like we are today where crude oil is a little bit off, a little bit softer and gas is strong, that you could see more activity go into the Mid-Continent, and we're definitely getting customers start to talk about that.

Great. And I know I kind of already talked about operating leverage, but just in the Mid-Con, there is spare processing and NGL takeaway there as well, right?

Yes, definitely processing, especially as we brought the EnLink assets in there. And what really as we put these together, we're able to make sure we can get gas to the most efficient processing plants as we continue to go forward. And when I mean efficient, they operate at a lower operating cost, but they also produce more NGLs. We're able to extract more of the NGLs out of the gas. So as we put these 2 together, we're really able to get gas to high efficient plants where sometimes before we had to use lower efficiency. But now as we see more growth, we do have the processing capacity to be able to handle it that we're not going to have to build more processing plants in the Mid-Con.

Makes sense. And then actually, just one more on the Permian and gas growth. You've been very tight on Permian gas egress for kind of ever. And then starting next year, there's all these Permian gas pipelines coming online. From talking to producers or just kind of your own observations, do you think that, that will lead to any kind of tick up and maybe on the margin, gassier areas now that you're not constrained anymore on being able to get your gas out?

Yes. I mean, obviously, in the Permian today, they're drilling for oil because gas, as we talked about earlier, the -- on the margin is not worth very much. Obviously, if you've already signed up for capacity, you're getting some money on your gas out of there. But there is a concern about that gas takeaway. But as you said, we got a lot of projects coming online as we go over the next couple of years. And when we look at those projects, obviously, we've been a participant in the Iger project that it's interesting that we're seeing from people wanting capacity. It's not all the producers.

In fact, lately, it's been more on the demand side. The LNG operators are the ones that are signing up for capacity on these pipelines to draw it in there because they know they need to be able to reach back into the basins to be able to feed this growing demand for LNG, especially more of these projects that are already at FID are completed and go into operation.

Jean Ann, the only thing I would add to that is there's the other component of the artificial intelligence, electric generation demand that's also pulling on that. You used to -- you had your supply push, which came from your E&P community taking out space and then a period of time where the utilities because of their demand for natural gas and the generation, they would pull in that space.

But now it seems to be the LNG and the AI demand centers are the ones that are also signing up for that. So I mean, but the demand we're seeing is greater than just about any demand I've seen in my career on these pipelines. And a lot of it is coming out of the Permian. There's some in the Haynesville and of course for source gas over in the Appalachian, but the easiest place to go get it is the Permian.

Makes sense. Actually, one more on sort of that theme. I think that the Bakken has sort of had some talk of a potential new gas pipeline going forward. Do you think that, that is likely to happen? And could that lead to a little more production of gas and NGLs there?

Well, what I would say is, obviously, we have the Bakken Express that's coming online here. That's the next thing up as we go forward. There is a pipeline out there has been talked about to go from West to East, may be driven by some AI data centers and stuff. So as it gets -- I think there's -- as we bring Bakken Express, there's going to be plenty of egress out of the Bakken for gas.

So bringing on another pipeline, I don't necessarily know that, that will have an impact on production. But when the Bakken Express comes on, obviously, people are going to feel better about getting their gas out as we continue to go forward. We have not really seen our producers talk about gas egress on what's driving where they drill and what they're concerned about.

Okay. That's helpful. And then I think more broadly about natural gas. Can you speak to your opportunities in general related to natural gas demand from LNG and power demand and how ONEOK will fit into that theme?

Yes. We already talked a little bit about our Iger investment that we're on that piece, and we'll feed that from our gas processing plants. And we said that we've had both producers and demand signing up for capacity on that as we continue to go forward. As we look at Walt mentioned a little bit earlier, we've been very excited about the EnLink purchase in Louisiana as that is -- there's some demand from LNG coming out of there. We kind of like the last mile. So we have the distribution system to get in there. So we've had a lot of conversations, a lot of opportunity.

We think a lot of opportunity in Louisiana to be able to not only go to LNG, but also into along the Mississippi River corridor where we see growth in industrial, hydrogen steel plants and the like that need a lot of gas can go forward. And then as we look through on our Permian side, OWT is a big header system out there, and we get up into Oklahoma. A lot of the AI data centers are looking where pipes are, they're laying pipe, they're putting their data centers close to pipes.

So we have quite a few opportunities that we're looking at. There are more lower capital type opportunities, nice returns, but a lower capital opportunity because they are placing these data centers next to where they can get gas for the power generation. So we think we're going to get our fair share of the AI in there, but we just don't see where we're going to have to spend a ton of capital on the AI side.

That makes sense. And then I think as another kind of just broad question, as you look ahead to 2026 and 2027, which organic projects, synergy-related projects or other drivers do you expect to be the biggest contributors to growth?

Jean Ann, I'll take a swing at that and Pierce and Sheridan can fill in behind. We've got a number of projects that start to come in, in '26 and then roll into '27. Probably the largest of those is the Denver expansion, which is fully contracted. We already are looking at potentially expanding that further. That's driven by demand primarily from the Denver Airport. You're seeing big expansion there at the Denver Airport, adding gates. And with that, we are the sole pipe into that airport. So jet fuel is leading the way, but just growth across the whole front range.

And then if there's any dynamic change within that market around how it's being supplied today, we're in a position to ramp up that pipe quite significantly and get quite a bit more volume. Sheridan mentioned the G&P plant. We're adding about 500 million a day out in the Permian. We're going to be in a position to -- that's where it kind of comes back to that bundling concept that we originally talked about with Magellan. We're working with a lot of the same customers in multiple basins, and that is going to pay dividends as we are out there in the Permian.

There are some little projects that we haven't given any real airtime to, but we were able to expand the capacity on the pipe out to our crude dock. We spent about $12 million, and that's going to be a multiple of that going forward from a return because we've effectively doubled the capacity of the dock by being able to kind of repurpose some assets and get a better optimized flow out to that dock. Medford comes on in 2 stages, the end of '26 and then the second stage in the first quarter of '27.

That frees up frac capacity down in Mont Belvieu. It resupplies the Mid-Continent with more purity product, which gives us opportunity up to the north system. Sheridan mentioned the Eiger pipeline. That's going to come on towards the end of that. We've got some gas storage projects. Those, again, maybe not huge, but we've got them in pretty much all of our areas where we already have gas storage in Oklahoma, Texas and probably most significant down in Louisiana.

So those are a list of a number of projects that are going to come on here that are not supply push really driven with the exception of the G&P out in the Permian that are already in motion, really coming towards completion. And when they're done, the only larger project that is under consideration is the refined products pipe out to Arizona. So you're going to see a step down in our CapEx. We'll have that operating leverage and be in a position to enjoy that growth and expansion of free cash flow without a lot of capital needs after '27.

Makes sense. And just as kind of a lazy back of the envelope, do you think it's fair to say that you'll -- even if crude growth is very slow in the basins that you're in, you'll still get the GOR growth for gas and NGLs and that ONEOK should kind of be able to maintain market share and kind of -- of that GOR growth and you can kind of just tag it to that. Is that like a -- once you kind of disconnected, I guess, from needing to spend capital in order to get that -- the base business growth?

I think that's a good way to put it. I mean that's what we've tried to build here at the company is build in that operating leverage. It's really not a matter of if things get filled up, it's just a matter of when. And like we said on our last analyst call, we're very confident in continued growth. We're focused on the momentum that we're taking into the fourth quarter here and extending that in. We're liking where we see on the volumes that are coming out of the Bakken. And so as soon as we can get our arms around exactly what these producers are going to do, and we'll be coming out with our 2026 guidance.

Makes sense. Yes, I guess just my last question was really just kind of about the path from here over the next 6 to 12 months is that the producers will kind of come up with their plans, they'll tell you over the next couple of months, and then you'll kind of wrap that into your '26 guidance, which will come out on your next earnings call. And then you obviously kind of have the synergies continuing to roll through in '26 and '27. But is that kind of how to think about the next 6 to 12 months for the stock?

That's exactly how to think about it.

Great. That was the questions that I had. I wanted to give you the opportunity if there's anything that I didn't ask that you think is kind of unique or missed about the ONEOK story to kind of close with that closing thoughts.

Well, what I would close with, Jean Ann, is that I'm very confident in the execution of our people. They've proven time and time again to rise to the occasion. It's the reason that we put innovation in as one of our core values. It's because we're constantly looking at ways and whatever environment that we're built, then that's what we're going to navigate through. And so that's what we focus on. We focus on how do we navigate through whatever environment that we have. And very, very pleased and very proud of our employees and the way they're stepping up to do different things. And like Sheridan said and Walt said, I mean, our employees just keep coming up with ways to improve efficiencies and to grow the company. And I think we're a good bet in the future.

Great. Well, thank you guys so much for making it with us virtually. sorry about your travel issues, and I hope to see you guys soon.

Thank you, appreciate it.

Thanks again. Bye-bye.

Bye.

Good morning, everyone, and welcome to ONEOK's Third Quarter 2025 Earnings Conference Call. [Operator Instructions]

With that, it is my pleasure to turn the program over to Ms. Megan Patterson, Vice President, Investor Relations. Please go ahead, ma'am.

Thank you, [ Bo ]. We issued our earnings release and presentation after the markets closed yesterday, and those materials are available on our website. After our prepared remarks, management will be available to take your questions.

Statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings.

With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer.

Thanks, Megan. Good morning, everyone, and thank you for joining us today. On today's call is Walt Hulse, the Chief Financial Officer, Treasurer and Executive Vice President, Investor Relations and Corporate Development; Sheridan Swords, the Executive Vice President and Chief Commercial Officer. Also on the call are Kevin Burdick, Executive Vice President, Chief Enterprise Service Officer; and Randy Lentz, the Executive Vice President and Chief Operating Officer.

Yesterday, we announced higher third quarter results and affirmed our 2025 net income and adjusted EBITDA guidance ranges. We also reaffirmed our expectation to recognize approximately $250 million of synergy-related adjusted EBITDA in 2025. Our third quarter adjusted EBITDA increased 7% compared to the second quarter, once again highlighting the sequential progression of earnings we anticipated this year. Compared with the first quarter of 2025, adjusted EBITDA has increased approximately 20%, driven by volume growth across our operations, steady demand for our services, and the consistent execution of acquisition-related integration strategies by our employees.

We believe that ONEOK's long-term market value will be driven by our strong fundamentals, contiguously integrated assets and consistent results from our diversification efforts. Key among these catalysts are ONEOK's significant operating leverage, contiguously integrated assets, synergy earnings with the majority being within our control, and our financial strength and flexibility. So let's start with the operating leverage.

We've either recently completed, or are nearing completion on projects that will add nearly 600,000 barrels per day of NGL pipeline cases, more than 200,000 barrels a day of fractionation capacity more than 550 million cubic feet per day of Permian Basin natural gas processing capacity, and an expandable refined products capacity to the growing Denver market. All of these projects are either complete, or are expected to be completed within the next 1.5 years. This operating leverage is a key differentiator for ONEOK, providing the ability to capture significant earnings uplift with limited incremental investments. Our contiguously integrated assets, including our extensive NGL and the [indiscernible] product system provides strategic connectivity and growth opportunities.

Regarding acquisition-related synergies, we remain on track to realize approximately $250 million of incremental synergies in 2025. By the end of this year, we will have realized nearly $500 million of synergies since closing the Magellan acquisition in September 2023, far exceeding our original expectation. We continue to see meaningful synergy opportunities ahead across all of our acquisitions with the majority of these completely within our control and not dependent on commodity prices.

Finally, our financial flexibility, strengthens our position and is the cornerstone of ONEOK's business. A strong balance sheet and an intentional and disciplined approach to capital allocation, and cash flow generation continue to support our ability to generate long-term value for shareholders. Our established and stable customer base includes some of the largest and most well-capitalized producers, refiners and downstream customers. Our combination of demand pull and supply push earnings, and our long-standing customer relationships provide resilience through different cycles. ONEOK's strong fundamentals and integrated assets position us well to navigate near-term challenges and continue delivering results for investors and customers.

I'll now turn over the call to Walt and Sheridan to provide the financial and commercial updates.

Thank you, Pierce. Third quarter 2025 net income totaled $940 million, or $1.49 per share, a 10% increase compared with the second quarter. Third quarter adjusted EBITDA totaled $2.12 billion, which included $7 million of onetime transaction costs. The acquired EnLink and Medallion assets delivered nearly $470 million in adjusted EBITDA during the third quarter, continuing their meaningful contribution to year-over-year earnings growth. Additionally, we benefited from higher volumes in our natural gas liquids and natural gas gathering and processing segments.

During the quarter, we repurchased more than 600,000 shares of common stock, and retired more than $500 million in senior notes through a combination of scheduled maturities and repurchases. Year-to-date, we've extinguished over $1.3 billion in senior notes through maturity repayments and repurchases. This combination of share repurchases and debt management reflect our commitment to a balanced capital allocation approach that utilizes multiple available channels to create shareholder value.

Our long-term leverage target remains at 3.5x, which we expect to approach in the fourth quarter of 2026 on a run rate basis. With yesterday's earnings announcement, we affirmed our 2025 net income guidance range of $3.17 billion to $3.65 billion, an adjusted EBITDA guidance range of $8 billion to $8.45 billion, which as a reminder, excludes the impact of onetime transaction costs. Year-to-date, transaction costs included in adjusted EBITDA have totaled $59 million. We continue to expect our total capital expenditures, including growth in maintenance capital to be in the range of $2.8 billion to $3.2 billion in 2025. As we finish out the year, we remain focused on capturing additional synergies and operational efficiencies with approximately $250 million in synergy contributions expected for 2025.

As discussed last quarter, we don't expect to pay meaningful cash taxes until 2029, which is a year later than we previously anticipated. Additionally, we expect our cash tax rate in 2029 to be below the full 15% corporate alternative minimum tax rate, which is also less than our historical expectations. Since The One Big Beautiful Bill, we now expect to pay more than $1.5 billion less in cash taxes over the next 5 years, and the corresponding increase in expected free cash flow supports our continued flexibility for capital allocation in the years ahead.

I'll now turn the call over to Sheridan for a commercial update.

Thank you, Walt. Starting with the natural gas liquids segment. Total NGL raw feed throughput volumes increased compared with the second quarter, driven by higher volumes in the Permian Basin and Rocky Mountain region. Rocky Mountain region volumes averaged more than 490,000 barrels per day, another record for the region and a 5% increase compared with the second quarter, driven by higher propane plus volume and continued strength in ethane recovery.

Gulf Coast Permian NGL volumes averaged nearly 570,000 barrels per day during the third quarter, and 8% compared with the second quarter driven by the continued ramp-up of newly contracted volumes. In the Mid-Continent, less ethane recovery led to slightly lower volumes compared with the second quarter, but we continue to see consistent [indiscernible] volumes from the region.

Regarding our fractionation operations. Our Mont Belvieu fractionation complex, including our MB-4 fractionator is back to capacity following the incident in early October. After initial safety reviews, we resumed operations at the majority of the complex within 72 hours. Repairs were made in operations at MB-4 resume within 10 days following an incident. During the downtime, we were able to optimize our fractionation positions in Mont Belvieu and the Mid-Continent, as well as utilize storage. We anticipate working down any inventory build related to this incident in addition to the inventory being held over from the second quarter over the next several months. As we fractionate and sell the inventory, we will be able to recognize the associated earnings.

We continue to see opportunities for ethane recovery across our system during the third quarter. Weaker natural gas prices in the Rocky Mountain reads have led to greater recovery opportunities, and we expect to continue to see high levels of recovery through the first half of the fourth quarter across our entire system.

Related to synergy products, we have now completed the primary Easton asset connections, including [indiscernible], East Houston and our Pasadena joint venture, providing key connectivity between our Mont Belvieu NGL assets, and key Houston area refined product terminals. Additional downstream connections will be completed through early 2026. Additionally, the build-out of connectivity between our [ Conway ] NGL and Mid-Con fine product asset is on track for completion by year-end of 2025. Both of these projects are expected to provide benefits through increased transportation fees in our natural gas liquids segment, which we have already begun to realize, and also blending uplift in our refined product and crude segment. It's also important to note that these projects provide transportation and blending opportunities with third parties, expanding the optionality of these apps further than ONEOK's own lending business.

Moving on to the refined products and crude segment. Third quarter refined product volumes increased sequentially, reflecting increased seasonal demand. When booking year-over-year, we continue to experience some regional supply disruptions along the system related to refinery maintenance, primarily impacting short-haul lower tariff movements. On average, refined products tariff rate benefited from the July adjustments, where we increased rates by mid-single digits as expected.

As of mid-September, we've entered the fall blending season. Liquid blending volumes in the third quarter and year-to-date have been higher than expected due to successful synergy execution. Physical blending volumes have increased approximately 15% year-to-date compared to the same period in 2024. Despite tighter margins from lower gasoline prices, increased blending capacity positions for a strong upside in a rising price environment. Our crude oil gathering and long-haul pipelines continue to perform well. Third quarter crude oil volumes increased sequentially demonstrating resiliency of our Midland gathering business.

Moving on to the natural gas gathering and processing segment. Volumes increased across all regions compared with the second quarter of 2025 as producers continue to execute the 2025 plans. Looking first at the Permian Basin. Volumes increased 5% compared with the second quarter, averaging 1.55 billion cubic feet per day in the third quarter. Currently, we have 20 active rigs on our dedicated acreage, driving the need for recently announced capacity expansions, totaling more than 550 million cubic feet per day across the Midland and Delaware basins. The Permian Basin continues to be a key area of strategic growth for us, and we will continue to be actively engaged in [ intentional in ] assessing opportunities to expand and enhance our integrated operations within the basin.

In the Mid-Continent, natural gas processing volumes increased 6% compared with the second quarter, highlighting producer resiliency in the basin and strong production results out of the [indiscernible] formation in Western Oklahoma. There are 11 rigs on our dedicated acreage in Oklahoma. Rocky Mountain region process volumes averaged 1.7 Bcf per day in the third quarter of 2025, a 4% increase compared with the second quarter, and a record for ONEOK in the region. Strong well completions during the second quarter drove third quarter volumes and will continue to benefit throughout the remainder of the year. There are currently 16 rigs on our dedicated acreage.

Looking forward, the current commodity price environment will likely drive more moderation and increased optimization of drilling and completion activities across the basins where we operate. However, even in a flat crude oil production environment, strong gas to oil ratios and continued production [ efficiencies ] point to modest growth in our natural gas and the NGLs across our systems.

I'll close with our Natural Gas Pipeline segment, which we reported another strong quarter and continues to exceed our original expectations for this point in the year. We continue to optimize the legacy EnLink asset and be opportunistic regarding natural gas pricing dynamics across our strategic assets in the Permian and Gulf Coast areas. We remain well positioned to help meet the growing demand for natural gas, both domestically and for LNG exports, with extensive pipeline network and key assets key asset locations such as Oklahoma, Texas and Louisiana. We are directly connected to major LNG and industrial customers, and continue to work on additional opportunities with them.

Additionally, we are in active discussions related to numerous potential AI-driven data center projects. The key to these projects remain speed to market, and our intrastate assets are located in premier natural gas supply and demand centers, close to many of these proposed projects, and are well positioned to meet the timing needs of the market. Pierce, that concludes my remarks.

Thank you, Sheridan and Walt. Before we move to Q&A, I want to close by emphasizing that we continue to see opportunities ahead. Importantly, we're executing on our strategy to combine our strategic acquisitions into an even stronger and more resilient business. Our integrated assets are performing well, expanding our reach in key basins and demand markets, and creating an even stronger commercial connectivity across our system. Our integrated assets continue to provide stable, fee-based earnings and position us to capture opportunities across market cycles.

We're able to execute our strategy because of the employees across our company. I want to recognize their commitment and contributions to our business, and our vision for ONEOK. Their focus on safety, operational excellence and innovation is a key to our success. As we look ahead, we remain confident in our strategy, our strong fundamentals and the catalysts that we expect will continue to deliver growth and long-term value for our investors.

Operator, we're now ready for questions.

[Operator Instructions] We'll go first this morning to Jeremy Tonet of JPMorgan.

This is Vrathan Reddy on for Jeremy. I appreciate you guys don't want to provide 2026 specifics at this point. Curious if you guys could frame up tailwinds versus headwinds as you think about earnings growth into next year. Should we -- specifically, should we think about that mid- to high single-digit growth still appropriate?

This is Sheridan. When we see our tailwinds, which push us into next year is obviously versus the synergies. We've put a lot of synergies in place this year, and we've got a partial yield into that. Easton being one of the big ones. We'll see a full year next year of that one also with the Conway NGL to Mid-Continent refined products, among others.

We also have our growth projects coming online with the Denver expansion coming on midway through the year. As we mentioned in our remarks, we have [indiscernible] over [ 500 million ] a day of processing capacity coming on throughout '26 into early '27. So the stuff coming on '26 is going to be a tailwind we continue to go forward.

And then also, we think there's just a growth in market share that we'll see in the Permian and some of our other areas continue to fuel our growth moving forward. So those are really -- as we see going forward, what's going to drive our growth into 2026.

Got it. And then on capital allocation, $45 million of buybacks in the quarter. Could you walk through, I guess, how you think about executing on the buyback versus debt pay down or other capital allocation priorities at this point?

Sure. Well, as we've said in the past, as we get closer to a clear path to our debt-to-EBITDA target of 3.5x, it's going to free up our flexibility to add some stock buybacks to the equation. We continue to be on track with where we think we need to get to from a debt-to-EBITDA standpoint. And with that visibility, we're starting to feel a little bit more flexible in our asset allocation, saw the opportunity to buy back some stock there in the third quarter and did a modest amount. We also saw a pretty nice opportunity on the [ bond ] side and executed on that as well.

We'll go next now to Michael Blum of Wells Fargo.

Maybe we just go back to the '26 guidance. The slide in the deck, you removed the mid-single digit to high single-digit growth [ language ]. So I just wanted to make sure I understand the change there and just how you're thinking about '26?

Michael, this is Pierce. What I would say is our focus is on finishing 2025 strong and carrying that momentum into 2026 year. They just went over several of those projects and the different things that are going to impact 2026. We're continuing to have discussions with the drilling plans, with our producers. We're going to be finalizing our 2026 guidance in early part of first quarter of 2026. But [indiscernible] in this way that we are very confident in our positive trajectory. So as far as guidance for 2026, I'll just ask you to stay tuned.

Okay. Fair enough. Appreciate that. And then just wanted to ask if you could quantify the potential impact of [ Waha ] spreads widening. Either can you capture that from your EnLink assets? Or do you have more open capacity on [ WesTex ] to capture those spreads than you have historically?

Michael, this is Sheridan. Obviously, the [ Waha ] to [indiscernible] channel spread has had a positive impact especially when you bring together our ONEOK West Texas assets, the West Texas system and the EnLink system and capacity we have on other pipelines, we've been able to leverage that to grow that. We've been able to do that not only on the EnLink side, but also on our legacy ONEOK gathering system. So it has been a positive impact going forward. We will continue to see us use that capacity as we grow our gathering and processing for our customers as we go on as well, but we have seen the ability to move [ gas on our ] capacity and also do a lot of parking [indiscernible] on our system as well.

We go next now to Spiro Dounis at Citi.

First question, maybe to start out with capital allocation. Curious that you guys are thinking about maybe where that next marginal dollar CapEx goes. And really, if you just dig into some of the basins or the asset types between NGLs, gas and liquids, what's most attractive to you right here?

Well, Spiro, I think we look at every project on a stand-alone basis. We've historically been able to use our strategy of building off our existing asset base that expand and extend approach, which has given us the opportunity to do some very attractive capital projects. That same strategy exists today with more assets. So given the acquisitions we've made, we've got more opportunities to expand and extend. So we look at each and every one of those is on a stand-alone basis.

That said, I think that our expectation is that CapEx will trend down here over the next several years. As Pierce had mentioned in his remarks, we have a lot of operating leverage in our existing business, whether it be NGL capacity, fractionation capacity that's coming on. So we don't need to continue to expand that. So we do see CapEx starting to trend down.

Got it, Walt. Second one, maybe just going to the Sunbelt connector. I was curious to get your thoughts on the competing open season that's out there, how you think your project stacks up? And if there's enough demand in Arizona for maybe everyone to win some business here?

Yes, this is Sheridan. I mean, I would say that we feel the Sunbelt Connector is a very competitive project as we look at the other opportunity out there Obviously, right now, we're still in the open season. We're still talking to a lot of the customers. We've seen a significant amount of interest as we end there. And we think a lot of that is driven by the competitive advantage of this pipeline has is that we are already connected not only to all the mid-cut refiners in the upper Midwest that we can pull that volume and source to this pipeline, but we also have extensive connectivity into the refining center on the Gulf Coast where we can actually do some very efficient expansions.

We already have capacity between the Gulf Coast in El Paso, and we have some very efficient capacity expansion that we can leverage and continue to go forward. So we think we're going to compete very, very nicely going in there. We'll just have to see how the customers come out and where we get them signed up, and how much [indiscernible] to see how which one of these projects will continue to be built.

We'll go next now to Theresa Chen with Barclays.

Following a notable uptick in volumes across your regions, I wanted to go back to the forward outlook a bit. Given the heightened market concerns around how producer budgets may be evolving in light of recent crude price volatility and understanding that the process is still underway. But can you just give us any sense of any early indications on how you expect volumes across your supply push assets to trend through the next year?

Theresa, I'll [indiscernible] here. But I think the way we look at all of our different basins are what is the drilling activity currently, and we know what the [ prepress ] is today in gas prices. And then we also look at how much -- how many rigs would it take in each of the different basins to basically keep the volume flat. And so we feel very comfortable that right now, the drilling is there to keep this volume flat. And if that happens, then we also have our GORs that are rising in particular, up in the Bakken, the GOR is [ 3.1 ] and every [ 10th ] means something up there. So by our calculations, there's enough rigs out there running to hold the crude flat, and flat crude volume. We believe our gas volumes are going to continue to grow.

Sheridan, you have anything to add?

We talked about the Bakken and we get into the Permian. We have enough forward visibility into volumes that are coming on our system today and people are completing here in the last quarter of 2025 that we will still see growth coming out of the Permian into 2026 and beyond. And we -- as we said before, we are very excited about the [indiscernible] formation and seems to have a lot of resiliency with [indiscernible] downturn in price up in the Mid-Continent. So we still look -- we're still very positive about our volumes going foward.

And Theresa, the only thing I'd add to that is, Sheridan mentioned this, but I want to make sure that this gets across, he mentioned competing for other volumes. That's the one thing. We all focus on, what's the drilling, what's the acreage dedications. But just as importantly, there's gas that's flowing out there right now that may be going to somebody else. And as those contracts roll off, we feel confident we're going to be able to compete with those volumes as well. And most of them are going into [indiscernible] so not a lot of capital to really connect to our operating leverage. So just a point I want to make sure that it's made.

And would you be able to provide an update on your LPG export commercialization efforts? How are those conversations going with potential customers? And what kind of interest are you seeing in the market?

Teresa, what I -- this is Sheridan. What I would say is that first thing is, as we've always said all along, we have supply to be able to fill the stock and that supply for a long time has drawn a lot of people to us, and they continue to do that, that we have a lot of interest in our [indiscernible] go forward. And what I would say on the contracting side of that, we are very pleased where we are right now with our contracting strategy and where we sit today. [ Still don't ] want to give a whole lot of details on that because as you all know, it's a very competitive market, but we're pleased where we are.

We'll go next now to Jean Ann Salisbury with Bank of America.

There's been some rumblings that there may be kind of a call on the MidCon gas complex over the next year or 2 to meet all the LNG that's ramping. Is that something that you're hearing from your customers?

And I guess, Sheridan, do you have a sense of if gas egress could become a limitation there for gas in [indiscernible] of the Mid-Con?

What I would say right now, Jean Ann, is we are seeing here some people maybe move to a little bit of a gassier portion of the Mid-Continent and moved through from that, which we've always said our Mid-Continent has a little bit of a gas option to it. As gas becomes more favorable, you will see some more drilling go to the gas side, which is good for our G&P and NGL area.

I still think we have quite a bit of room to go of growth in the Mid-Continent before we really run out of egress out of the Mid-Continent. And I think we'll be ahead of that as well. We [indiscernible] getting closed, we'll be able to put [indiscernible] in place to be able to get more gas out of the region. So we're -- that's one of the reasons we have some conviction in growth in the Mid-Continent on our volumes as we're also seeing that move to a more gassier play.

That makes sense. And it seems like year-to-date in your processing and NGL volumes Bakken is trending a bit above the guide and Permian is trending a bit lower than the guide. Can you just talk about the dynamics of that and how much has to do with ONEOK's market share in those basins versus basin growth overall versus your expectation?

Well, I think really start with the Permian and the Permian -- we kind of -- because of some larger [ pads ] were delayed in the first part of the year, we kind of came out a little bit slower than we had expected. But as those pads come on have come -- have come on, and our [ goal in ] now, we are now out of volume across our system where we expected to be at this time when we set our plan together. So we're pleased where we are right now with our volumes in the Permian Basin.

Up in the Bakken, we have on the NGL side, we have seen some record volumes in there, and a lot of that -- kind of that high end of that has been due to ethane recovery. We talked about our discretionary ethane that we can bring on, and we've seen some pretty wide spreads between -- with the low cost of gas, or low price of gas up in the Bakken over the summer, we were able to take advantage of that and put ethane on our system and delivered into the -- that will be [indiscernible]. So we've been very pleased how that's going, and that will continue into the fourth quarter.

We'll go next now to Manav Gupta with UBS.

We are in the middle of this AI revolution. I think NVIDIA's market cap went and hit $5 trillion this morning. And I'm just trying to understand, in your comments, you did mention all the ways -- some of the ways you can benefit from this revolution. Can you elaborate on it? Where could ONEOK see the opportunities as we get into this data center build frenzy in the U.S?

Yes. This is Sheridan again. What we're seeing is we have been contacted by I mean, well over 30 different projects on -- for data centers. And they were putting those projects in close to natural gas pipes to be able to be the electric generation, they need for those data centers. And so we've had our fair share of look at those, and we have some where they are very close to our pipeline that we feel we have the competitive advantage to be able to supply those. These are not going to be high capital type projects. They're going to be very nice low capital, nice return type projects. But we are seeing -- a good number of them that we think that we have the competitive advantage of either speed to market and how close we are to the data centers that we're going to win our fair share.

Perfect. My quick follow-up here is you and your partners recently announced the [indiscernible] Express pipeline. Help us understand the importance of this project? And why do you see the need for this project to go ahead?

Yes. On the [ Ike Express ] product, we're really excited about that as we continue to see the demand from LNG and a lot of that demand is needed to be supplied out of the Permian Basin. We still see growth in that area. The [ Iger ] was a nice complement to the [indiscernible]. And because of the ownership we had in [ Matterhorn ], we were able to see inside of that. And that project was FID when they had enough firm commitments from customers to be able to make an acceptable return. They've been continuing to be able to get more contracts on that. So we're very pleased where the [ IGR ] project is going, and it allows us to put complete our integration, be able to put gas out of our gas plants onto a pipeline that we get some equity back in and be able to grow with it. So we're very excited about the [indiscernible] project.

Well, the only thing I'd add to that, Manav, is that you've got the capacity that's currently out of there. One of the reasons that you see some of the widening of the spreads is because of the tightness of that capacity. So there is extra capacity that's needed in the 10 Bcf of LNG that's been basically built down in Louisiana and Texas, primarily in Texas. It's going to need this gas. And so it's not like we're building the pipe for 10 Bcf. It's just only [indiscernible]. So the demand side of this thing is very positive to fill it up.

We'll go next now to Keith Stanley with Wolfe Research.

I wanted to follow up on Sunbelt first. So in the past, you've talked to potentially working with partners. Could that include refiners or other strategics? And are there any discussions going on, on that front that could help commercialize the project?

We've commented that we would deal with partners. And what I would say, they need to be a strategic partner. They need to bring something to it. And we're continuing to open to that. Obviously, if there's we would not comment on any conversations that are going on at this time, but we are open to a partnership as we've said before.

Okay. Great. Second one, I think in the prepared remarks, you alluded to the Permian as kind of a core strategic focus for the company. Given it's a very competitive market, especially these days, do you feel like you could benefit from more scale in the Permian overall?

And then separately, can you remind us where you are in the process of some of the EnLink volumes transitioning over to ONEOK pipelines in your system?

I'll start with the last one first. I mean on the EnLink volumes, I think you're talking about the NGL volumes coming off of the legacy EnLink plants that are not going to the ONEOK NGL system. We will see those start to come over. They're roughly around 50,000 barrels a day. We'll start seeing them come over from '26 through '28 in the time frame when those contracts come up and they will -- once those contracts are finished, they'll come right over to our system as well.

Obviously, we like scale in the Permian because we're growing in the Permian. We're already talked about adding another 500 million a day of processing capacity in the Permian. So we like that. We like to grow it there. We like to grow organically first because that is the most economical way to growth. As we look at M&A, we look at everything out there, and we're going to be very intentional and disciplined to -- if we're going to do anything more on the M&A side.

We'll go next now to John Mackey at Goldman Sachs.

You talked about I think in response to Jean Ann's question, just the ramp on kind of Permian G&P relative to the guide. Can you also just spend a minute or 2 on the crude side? I think also the year-to-date is looking a little softer versus the full year. Maybe just bridge us to the volume guidance. And then again, if you're talking about a rig environment that gets you to flat next year, how we think about that piece of the growing -- the business growing into '26?

So when we look at our crude volumes that we think about, we are down just a little bit on that piece, but you really got to break that apart into its components. Really, the area that we are down on is mostly in our low volume -- I mean, a high-volume, low-margin business that we're down on. The main business up gathering crude out there, we were in [indiscernible] there, and we are excited about the continued growth there.

So you got to look at our crude volume in [indiscernible] long-haul, the HDS system in Belvieu. We have some short-haul volume out in the Midland that all are down a little bit. But the core -- what I call our core business, the core business have taken it off of leases, or batteries and move it through our system is where we expect it to be, and that's really the driver behind that business.

All right. That's helpful. I appreciate that. And maybe staying in the segment. Now it's the Easton kind of integration pretty well done. You're going to get more on the Conway side tied in next year. Are you able to frame up in kind of, let's say, like a mid-cycle environment, or what have you? This overall size of the blending business on a kind of, like, annual run rate basis at this point?

I think when you look at the blending business, you've got to be very -- there's a spread component in there. So it fluctuates from year to year. What I would say is that through our synergies and everything else, they had in my remarks, we've been able to increase the volume by 15%, which really sets you up for when prices go back to more normal, spreads go back to more normal, we'll really be able to take advantage of that opportunity continue to go forward. And as we put more of these synergy projects in place, we're going to be able to increase that money, that blending uplift that we have, being able to make sure we have volume there when we can blend and be able to get to places where before we're uneconomical to get to.

So it is -- as I remind everybody is that 90% of our business is volume times fee and that last spread and commodities is only 10%. So even our blending business that we like very much so, and we're growing still a small portion of our business.

We'll go next now to Sunil Sibal at Seaport Global Securities.

So I just wanted to go back to your comments on the guidance. I realize that your focused on ending 2025 strong. So in that context, realizing that we had [ them ] before incident also, is the midpoint of the full year guidance that [indiscernible], still a good kind of an anchor point for -- as far as fourth quarter goals are concerned?

Well, I think what we said is that we are confident to be within the range. We've affirmed that range. And we're going to see how the fourth quarter continues to play out. But at this point, we're going to keep it in the range, and we're very confident of achieving there.

Okay. And then one clarification on Bakken. From Sheridan's comments, it seems like you mentioned that you have 16 rigs running on your system. I believe last quarter that was 15. So is there a pickup in rigs? So first of all, I want you to clarify that?

And then how should we think about that number trending, especially as you go into discussions with your customers?

Yes, it is up one. I mean, there's a lot of flexibility in those rigs moving on and off, but we are up [indiscernible] we like. As we think about trending into 2026, the producers are still in their budget process right now. As they continue to come out that, we hear more from them. We'll be able to reassess what 2026 looks like in terms of rig count and volumes and everything else like that. But we have good momentum into 2026, so we like, so we're optimistic.

We'll go next now to Jason Gabelman of TD Cowen.

I wanted to ask one just on the quarterly results. In your disclosure, you talked about the NGL segment benefiting from -- it seemed like selling product out of inventory and refined products from timing of operational gains and losses.

I was hoping you can elaborate on those comments a bit more as I'm trying to understand the underlying earnings in the quarter. And I have a follow-up.

Well, this is Sheridan. On the NGL side, we talked about selling purity products out of that. This is in our marketing business, there's different times that we have -- we may be holding product for storage and selling at a different time of the year. And so because of that, we'll maybe moving earnings across quarters a little bit. So we saw an uplift by being able to sell some product in the second quarter -- I mean in the third quarter. So it's really kind of a timing of sales as we -- on our marketing business.

And on the refined products on our over and shorts. If we look out over the year, we tend to be just slightly a little bit long on volume, but we take opportunistic time throughout the year to sell our open [indiscernible] into the area, and this is the time that we sold in the second -- in the third quarter.

Okay. Got it. And my follow-up is a bit more strategic in nature. It seems like your growth rate -- your EBITDA growth rate is obviously [indiscernible] here from very attractive rates the past few years you've previously said mid- to high single digits. We'll see where it comes out next year. But as you think about attracting capital to your equity, how important is it to maintain our competitive growth rate? Or do you think that your EBITDA growth rate is not necessarily a main determinant of equity capital you could attract to the stock and there are other avenues to do that?

Well, I mean I think, clearly, having a growth rate -- a positive growth rate is going to be something that attracts people to the stock. I would just kind of point you to our history. We've gone through cycles before where commodity prices have been up and down. And year-over-year since 2014, we've had positive EBITDA growth every year. We continue to see that trend.

Clearly, at the moment, we need to get a little better fine point on where the producers are going to participate in the coming year before we provide a very specific number, which we'll do in the first -- beginning of the first quarter. But the business is incredibly resilient. And we are very confident that we will continue to grow into 2026.

We clearly are going to be focused on our capital allocation, taking the opportunity to bring on real high-quality projects. But if you look at our cash flow profile, we should have the opportunity in the coming years to be in there buying some stock as well. So that could have a positive impact. But at the end of the day we continue to achieve that earnings growth going forward.

The only thing I'd add to that is I'd encourage you to go back and look at the data for, like, crude oil prices between 2008, 2009, 2015 to 2016, 2020. It really paints the story of what Walt just said, about how we've been able to grow our EBITDA through these different down cycles. And one thing I would say because most of us have been in this business over 40 years, with every down cycle there's usually an up cycle. You don't get into another down cycle, so you have an up cycle. So it will come back, and we're confident to manage through the down cycle.

Ladies and gentlemen, that will conclude our question-and-answer session. I would now like to turn the call back over to Megan Patterson for any closing remarks.

Thanks, Bo. Our quiet period for the fourth quarter starts when we close our books early next year and extends until we release earnings in late February. We'll provide details for that conference call at a later date. As a reminder, our IR team will be available throughout the day for any follow-ups. Thanks, everyone, and have a good day.

Thank you, Ms. Patterson, again, ladies and gentlemen, that will conclude today's ONEOK Third Quarter 2025 Earnings Conference Call. Again, thanks so much for joining us, everyone, and we wish you all a great afternoon. Goodbye.

Hello again, everybody. For those who don't know me, I'm Keith Stanley, I run our midstream group here at Wolfe Research and very happy to have ONEOK senior management with us as well today. We have Pierce Norton, CEO, Sheridan Swords, Chief Commercial Officer. Sorry, Sheridan; and Walt Hulse, CFO.

So thank you all for joining us. As I said in the last one, please feel free to throw your questions in, just raise your hands and happy to have you participate in the conversation. Maybe we could start just strategically with kind of a look back in time. The company has been probably one of the more acquisitive in the midstream space and roughly double the size of the company with M&A. So can you just talk through some of the strategic rationale on some of these transactions? And how you're positioned looking forward if you expect to continue to be fairly acquisitive in the future?

So I'll start. Well, Sheridan, fill in on this. But I think our inquisitiveness actually goes back all the way to the early 2000s. We went through a period of time back there where we actually did quite a few acquisitions. The theory was that you get yourself positioned acquisition-wise, to expand and extend all those assets that you're collecting. So we did that, and then we kind of went through a period of organic growth where we spend billions of dollars across the middle part of the United States, aggregating these different assets that we bought. And then we ran into a period here where we felt like that we needed to do more M&A on the specific criteria. So we socialized that with the Board. We came up with this holistic criteria that we're looking for.

We created some questions around that. And before we did any sort of looking at companies and then we started putting these companies kind of through this filter. And then that's where we ended up doing Magellan, we did Easton, we did EnLink. We did Medallion and several of these companies, we've actually done, I think, 5 acquisitions company NGP in 2 years. So we're very pleased with where we are right now. We feel like we're back in a position now where we can continue to expand and extend. So they're good projects that we're doing these extension zone, but they're also complementary because they're contiguously integrated to the assets that we have. So we're in a position now where we can be very patient about what we do next, and our focus right now is on integration.

Pierce, I think I recall a time in the past where you said there was actually a list of companies that you identified as ones that you could add value to. Is that list now smaller today, would you say, on potential opportunities that make sense?

Well, I would say they're different because the list is it more because of what it is the criteria that maybe you have satisfied currently, but you still need -- see the need of doing some other things. So I'll give you a couple of examples. One of the things that we want to do originally back in 2021 kind of time frame, it took us until 2023 to get it done. But is to diversify, try to diversify a little bit out of the Bakken and to some other areas we wanted to go into businesses that were more what we call a demand pull instead of demand push and which kind of get from supply and demand is another way to look at that. So having done that, we do we still want to diversify even more Sure.

But right now, expand and extend is our main focus. So as the criteria changes, so do the possibilities of the companies. But right now, we don't see anything out there that we can't be patient on. And so we're going to continue to do what we're doing, which is continue integration, continue to get through. We'll talk about this probably a little bit, but what is it that we need to do to prove to the market that we're -- we have the great assets that we have.

So Walt, you had any other comments on that?

No. I think that if you go back to that original criteria, we were looking for something that was going to be credit-accretive that was going to give us scale. We clearly think that we achieved a couple of those and kind of took them off the list and putting ourselves in a position. Pierce mentioned that we had spent a lot of capital growing the business originally. When we got to about a $4 billion mark in a 10-year period, we went from $1.4 billion of EBITDA in an 8-year period to 4. And then we saw that we really needed to do some things to reposition the business for the next couple of decades to get ourselves back in a position where we would have an asset base that we could expand and extend.

So we did the acquisitions that we've done. Now you look at some of the projects that have come off of that, like the Denver expansion of the refined products pipeline to feed the dumber or international airport. That's a perfect example of taking the new assets that we acquired and using our model of extend and expand into a new market. continuing to grow those assets off of the existing footprint.

Okay. So I think you mentioned kind of convincing the market of the strategy of the acquisitions. What do you think the market is misunderstanding or underappreciating about the ONEOK story these days?

I think it's just how to model the business that has done 5 acquisitions in 2 years. I think that's the biggest thing because we had gotten very predictable. We still actually are predictable. It's just that once we go through, we don't give quarterly guidance. We gave an annual guidance when you look at kind of won't be printed in the first quarter, multiply by 4, you come up short of what our guidance was for 2025. So I think there is some skepticism there. And as we went in the second quarter, we proved the second quarter has been in the first quarter. We're about to print our third quarter numbers, you'll see what those are here shortly.

So I think it's just a matter of proving the people, here's what these assets can do together and seeing the different profile that these assets have together over a year and understanding what is it that changes from quarter-to-quarter that makes these earnings go up. And I think once we get through another couple of quarters here, I think a lot of that is going to be well understood.

So with that backdrop, any commentary on how volumes have been tracking in some of your key basins relative to expectations through the summer months?

Yes. I mean, obviously, we always see an uptick in volume through the summer months. We've kind of said for a period of time that we get winter. I tell everybody, we get winter every year in the Bakken. So once we come off from the Bakken and the winter and sometimes takes a little bit to come back on. Had a little bit winter weather earlier this year. And so our volumes are ramping to a level that we are getting back to where we thought they could get close to at this time of the year. A little bit delayed. There has been a little bit of tamping of volume on some of the producers but we're still growing, still look to continue to grow into the future as in the Bakken.

The one that's really been kind of a surprise to us here, not just issue for the last couple of years has been the Mid-Continent. There's a Turkey formation over on the western edge of the state that there's 4 or 5 different producers out there that have really been leaning into that and been growing that area out there that has actually -- for a long period of time, I thought the Mid-Continent would be kind of flattish to stand forward, but now we are actually seeing growth from that area has continued to go forward.

Out there, then the Permian is growing. We continue to grow in the Permian. Continue to see those volumes come up. Continue to poke up CDPs. Continue to see growth out of acreage that's been dedicated to us on the inlet volume that continues to come on. So on the G&P side, all the areas we're seeing growth even though admittedly, a little bit tampered down from what we thought it would be when we had $75 crude oil versus $65 crude oil we're seeing today, we still see good growth on that. And the NGLs kind of reflect that as well, as we continue in there. We still continue to grow across that. Our growth out of the Bakken has been a little bit more better than -- has been good this year versus the G&P, and that's because of our discretionary ethane. We've seen a bigger opportunity this year to bring more ethane out at wider spreads than we have in the past. So we've been able to go -- so you get a little bit of uptick on that side of continue to go forward. So overall, I think we're sitting in a very good spot heading into the back half of this year.

A little more color on the on the Bakken as it relates to winter. There's two factors there. One is, A, it gets told, everybody knows that, right? But a producer will turn almost, call it, a heater treater during the coldest part of the winter to keep the oil flowing, which is where the -- most of their economics come from. Well, that actually takes away they'll take that off the tailgate of where they're producing from and actually use that in a heater tree. So it actually turns our volume down about 10%. The other pieces are what is the severity of the winter events that you have. So the cold weather actually is not -- it doesn't move the needle as far as shutting in volumes or whatever, but a severe windstorm ice storm, 4-foot snows that cover the road, so the producers can't get in there to service their wells. Those are the things -- those are the two main factors that happen in the Bakken.

Sure. And any comments across your geographies on your expectations for 2026? Understanding that producers haven't fully finalized their plans. Just assuming oil prices stay around where they are in kind of the mid-60 levels.

Where we see now in producer activity in our areas we see in the Bakken, we've seen modest growth up there on the GAAP side of it, there's enough activity to keep that going forward. Obviously, the producers, as you said, are in your budgeting time frame. Due to the quality of producers we have in that area, we really don't see them making a material change in what's going on in the Bakken. So we'll see -- we're really expecting to see some loss growth going into 2026. We talked about in the Mid-Continent. As I said, we're very pleased on that side. The one thing I always think about the Mid-Continent is almost like an option that we have on gas prices. Do we continue to see more LNG come online if we see any more uptick in gas prices, you could see some people in the mid-continent.

I talked about the Cherokee, but in the SCOOP and the STACK come in and go to more of the gas part of that play, which still is pretty NGL rich forward. The Permian is -- continues to be the Permian. I mean there's some people talking about there may be a little bit of a slowdown on rigs in there, but we are seeing producers being much more efficient, drilling longer laterals, being able to get more out with less, and we still consider to see pretty good growth coming out of the Permian going forward. Overall, we see crude oil being fairly flattish, around 13 million a day out of the United States. But you still have to even maintain , you're going to have to drill. You're going to drill different areas. And so we think that Permian continue to grow at the detriment of some other areas we'll be able to keep up with their declines. People won't fell as much as there, but we definitely think that Permian is going to be one that's going to take up a lot of the slack on the oil side, which will make much greater.

So with the volume growth you expect, so the company has a target of mid- to upper single-digit growth in 2026 EBITDA. Can you walk through what is the basis for that. Volume growth sounds like you're expecting modest volume growth kind of across the system. How important are some of the capital projects that you're bringing on? And then how meaningful are some of the remaining integration-related synergies to your '26 growth?

Sure. Well, it is kind of a different story this year than it has been historically over the previous years, where it was very volumetric driven by producer activity. Clearly, we are 90% volume times rate based on a fee. So that's our key business. But we've got a number of projects, some of them synergy-related that are being completed right now and will be completed as we go into the balance of the year or in 2026. Each of those kind of gives us an incremental stair step up. And a couple of examples. When we bought Magellan, we needed to connect our Mont Belvieu facility to the 3 distribution centers in East Houston. We were going to build a pipeline to do that. That was going to take us about 3.5 years.

We had the opportunity to buy Easton. When we bought Easton, but we still had to connect that to the other -- to all those entities. We're just now completing that kind of as we speak. And that now enables us to get that next wave of synergies out of the Magellan acquisition. And what it really is doing is it's providing us the opportunity to provide blend stock to not only our own assets but to the customer assets at these various terminals out of our system. Up until this point of 2025, that opportunity didn't exist. So we now see that kicking in, and it will go forward in through '26 and beyond. We were doing a very similar thing where we connected our Conway frac facility to Kansas City, Tulsa and Cushing to enable us to vastly reduce the logistics of blending around the Magellan system in the Mid-Continent. That's going to be completed here in the fourth quarter. So we'll see that full benefit going into 2026.

In 2026, we're going to complete the Denver project, where we're expanding the refined products line out to the Denver airport. That's a fully backed project. There's enormous growth at DIA. And so that's been driven by jet fuel, but gives us an opportunity to serve all products as we can batch up that line. So that kicks in '26 as well. And then there are a number of smaller projects that we haven't even been out public with, but they are basically just taking either pinch points away or making connections. Another good example would be Medallion as we continue to make the connections to get Medallion volumes on to our long-haul crude pipes. We start to see that continue to fall in.

Those are -- there incremental stair steps, we're still going to see nice volume growth across our system. And typically in previous years, that would be what really kind of drove growth. But here, we've got some stairs step so they're going to take us up.

I guess what would you say are the key risk to executing on that 2026 growth outlook and your level of confidence in it right now?

Well, I think that everything I just described is completely in our control. So I don't think there's a whole lot of risk. Most of it is in the later stages of completion from a construction standpoint. So I really don't see that as an issue. Clearly, with crude in the low 60s, we're going to need to see what producer activity is across all patients. To the extent that, that slows a little bit, that could have a volumetric impact that could slow the growth. We do think we're going to continue to get growth in each of these basins. Potentially, maybe not at the rate that we thought it was gonna be. So that to me is probably the biggest risk.

But I think it's important to note that in '16 and then '20 when crude broke down into the 20s and in 2020, it went down to negative and came back up. When we were coming back up through the 40s, you would hear producers say, if we could only get to the 60s, we will coin money. Well, they're going to take to 75, 80, and that felt real good for all of us. I mean, we all enjoyed that. My sense is that if we stay here in the 60s, that will go back to being the norm and they can make good money in the 60s, and they'll continue to press on. We have the benefit of having kind of the who's who of customers. Most of the majors or the large independents that are going to continue to drill through cycles. They want to maintain their crews. They want to continue to produce. So we don't expect them to really back off in this environment.

Any questions in the audience at all? Okay. I wanted to ask on the Sunbelt Connector project, definitely an interesting one that I think people probably weren't expecting big refined products pipeline that would run from El Paso, Texas to Phoenix. Just what you're seeing there as far as the opportunity level of customer demand potential cost and returns for a project like that.

So really, when we think about the SunBelt connector, what we're seeing is, is that today, Phoenix is a growing market. It's growing from population, which is driving unleaded demand growth. And we're also seeing a growth in Jet fuel as they expand their airport out there. Right now, Phoenix has said by 2 pipelines, 1 pipeline is coming from El Paso into Phoenix, and that one is full and the other one is coming out of California into Phoenix as well. And as we see rationalization of refineries in the California area, we see that more and more of that refined products is going to want to stay in California and I say "we" and that there are a lot of -- the people were talking to, share this point of view, going forward. So we see an opportunity to be able to line into Phoenix and be able to bring in not only refined products from the Gulf Coast through our system, but also from coal in the Upper Midwest as well. And we've had people talk to us about being put on this system.

So -- and definitely, with the administrations that we have in there right now, we think we have a unique opportunity to be able to get some pipeline like this in. And we saw enough interest as we talk to different people and done all the scoping and everything else to go out and do a binding open season. So we have a 2-month open season that we're talking to people getting men on what that's going to be. And the cost and return is what we have is -- we've looked at under many different scenarios of how much people would sign up for. And depending on what they sign up or is going to drive what the capital cost can be. So we have some different scenarios where if depending on where it is larger or smaller, what capital we get put in there to go ahead and get this pipeline in either put into a case where we could ramp up to it or put some optionality and to upsize it a little bit in the beginning.

So we really need to see what comes back from our customers and how much they're willing to sign up will really tell you how about the capital is going to be on that. It will be -- we talked about, we think it will be a very nice return on this project. One is we will put a little bit bigger pipe in the ground. We've already said we're going to put a 24-inch line from El Paso to Phoenix. And that -- what we don't need -- we've not seen the demand from our customers for our pipeline that big. One thing is if we get a lower level, we will have to put any pump stations on that so you won't have any power cost. It's going to be very easy to move it out there. But putting that bigger pipe in gives you the opportunity to expand it into the future. If you continue to see more rationalization in California, continue to see growth and you need more pipeline capacity in that we kind of see it as a onetime shot to be a pipeline in there, we want to be able to put additional pumps on there and to be able to expand the capacity. And if you do that as we've done in other 5 lines, and the return on the project would be very, very nice.

And what's the time line and permitting look like on a project like this? I think we all know what the gas pipeline project would look like. But what does it look like on the pipeline?

On the liquids line, you don't have to go through the FERC process. You still have to go through the EPA and the core of engineers and typical process they have to go through on any pipeline. But what we are seeing at this time is on some of our other projects that we're doing whether or not that be the Denver expansion or our Texas City export dock is that we are getting permits to lot worker than we were in the past. And so that time frame has really been on down. So right now, we think it's under 2 years to get ir permitted.

And then about a year or 2 construction?

Right.

On CapEx, so -- it's a little -- I mean, the company is $3 billion of CapEx this year a growth CapEx. What's interesting about ONEOK is you're actually still kind of like free cash neutral-ish at $3 billion of growth CapEx, whereas a lot of your peers are free cash negative in the current spending levels. How are you thinking about CapEx over the next few years for the company? Are you looking to really grow faster and potentially keep up $3 billion or higher of CapEx? Or is this going to turn into more of a free cash flow and capital return type of story?

Yes. No, we won't continue at that $3 billion next year, just given the carryover of the projects that we have will likely be close to around where we are in this year. But as you move into '27, '28, '29, we're going to see that tail down. Clearly, the Sunbelt connector, if it was to come on as a large project. But we think that if we -- if we move forward with it because we get the appropriate contracting, we'll likely have a partner in that or will utilize project financing. So we won't take that fully on our balance sheet as we have in the past with some of the pipes. So I would expect to see a meaningful step down in CapEx as you get out to 27%, 28%.

And that actually is interesting because it comes in at the same time that the new big beautiful bill is going to give us the tax savings. We're going to have about $1.5 billion of incremental cash flow from tax savings because we're going to be able to utilize 100% bonus depreciation, which will move us up to not being -- it will still be at that kind of no tax rate type of environment through 28 and will start to go up to the which is 2 years later than we thought it would be.

So on the balance sheet, I think your target is to get to the 3.5x debt-to-EBITDA by the end of next year, so not quite there, but with clear visibility to get there. How do you think about stock buybacks right now? Because the stock valuation, in my view, anyway, has gotten very attractive at this point. But you're still a little bit above the leverage threshold of where you want to be. So how are you weighing that? And how much flexibility do you have for buyback?

Yes. Well, we clearly -- we're focused on getting leverage down. We've cash called, I think, 4 of the last 6 bonds that have come due. And as we get more visibility, clearly, we -- our flexibility around stock buybacks increases. We are in a position where Moody's wants us to be at 4x for mid-BBB or to S&P wants us to be at 3.75%. So our target is actually more conservative than the agencies. So as we get to that -- that's a 3.6% run rate at the end of next year. As we get visibility of that, we do have some flexibility if we were to delay that ourselves because of some actions we took and still kind of got through the rating agencies benchmarks we defined. So I don't think anything that we would do has necessarily changed the trajectory of that reducing credit metric. So our flexibility is increasing.

Okay. I wanted to ask about ethane and the market overall because the one thing that strikes me, you have still a fair amount of unrecovered ethane in some of your regions that you could benefit from? And it feels like we're getting a step change with some of the export projects just in terms of ethane demand in the U.S. If you look at EPDs, Natus River project, energy transfers Flexport. It's a pretty meaningful step up in total ethane demand in the country. How do you think that plays out in your regions as far as ethane recovery over the next few years? Are you expecting to have more opportunity to recover more ethane and ship it down to the market?

Yes. I definitely think there's going to be an opportunity. I think it's really going to come into the Mid-Continent range is where it is. We've always said that we think the Permian is always going to be in ethane recovery -- the Bakken is always going to be in ethane rejection unless we decide to bring some ethane out on our integrated system. And so really, the Mid-Continent, we've always said it's going to be in and out of that. So the thing you have bots they bring those projects on, they're going to increase demand, that's going to increase the price of ethane spread it out. We should be able to give a little bit more in you got to balance that with how much more growth is going to come out of the Permian.

The Permian grows more, that's going to bring more ethane on, so there's a balancing effect in there that's going to happen to support. But overall, you're right, it's very positive for us on the ethane that we're not extracting today on full rates, and that's going to happen in the Mid-Continent.

Would you ever consider ethane export projects yourself? From what I understand, the international demand is pretty high, but it seems like your past exports has been to do it in a more brownfield way? How are you thinking about ethane exports?

So one thing we looked at ethane exports for a period of time, just like we looked at LPG exports for a period of time. One thing we found out is that on the ethane exports, any export is beneficial to us. This is you said, because it increases the price of that to increase the pull of ethane. If that pulls that out of the natural gas stream, we're going to get the pull-through effect on our doesn't necessarily have to be our ethane exports. The thing that has got us a little bit is just a period of time we were looking at it, most of these ethane exports are going to China. And that's something that becomes a little bit more difficult to wrap your hands around.

Which is much different than in LPG exports where we want to make sure our product moves across the thing. When you're dealing with propane, propane has to come out of the gas, ethane, we at least have the toggle that you can't find a home for ethane on the NGL side, you put it into the natural gas. You do have a way to clear. But we are -- we're very supportive of the 2 ethane projects coming on, and we think it will have a positive effect to us just how much it weights.

The one thing I've been thinking about more just with -- I mean, the LNG market right now and all these projects getting sanctioned, it's -- it's almost becoming a little overwhelming. The amount of gas demand we're going to see from all the LNG, especially if it runs at full utilization in the early 2030s. How is the company positioned to benefit from this, whether it's the Louisiana gas system or even maybe a little more far out kind of concept of some of these basins like gas areas of the Mid-Con or the Barnett, are we going to see a call on some of those areas where your infrastructure might see greater utilization because of all the gas demand on the Gulf Coast.

Yes. Definitely, as you think about Louisiana, Louisiana, we are tied into some of the LNG down there today. We kind of see ourselves as the last mile in that area, and we do see some of the new projects coming online will be in Louisiana. So we're already taking advantage of that and growing on that side of it, not only for the LNG demand, but we're also seeing it for industrial demand around the river port. So we're very excited about Louisiana. And that was one area where we bought EnLink, we didn't put a whole lot of money and a whole lot of value on the Louisiana natural gas assets, and that's been a really big as we've got in there, we've really seen some opportunities to be.

We see that as a demand pull. Louisiana is a demand pull to us on our system on the LNG. But we didn't -- when you think about it, is all that demand coming online, another 10 Bcf coming online is going to have an effect on the natural gas price as it comes up. And we think in the Mid-Continent, we've always had an always thought of it as we have an option on natural gas enterprise gets up, you're going to see more people want to move into the gas airport or the SCOOP and the STACK, more in the central part of the state and to produce that higher gas value because you can get some pretty big gas wells coming out of that, that still are pretty rich in NGLs.

So we definitely think this keeps coming online, you'll see be more pulled out of the Mid-Continent as well And then definitely, the Permian is going to have to carry the load on a lot of this coming out, see more demand more as prices rise, you're going to see more drilling in the Delaware and Delaware is a much more gassier area. Wells come on with a lot more gas, more of the return comes on the gas side. So we actually see there will be more coming out of the Permian, definitely in Delaware. So we think that LNG is going to have an impact on the system as we continue to look out at the 10 Bcf of projects come online.

Will there be enough dry gas going through?

Yes. I do think you'll get some dry gas scaling. I think Haynesville could be very much very close to the Louisiana, and that's where our Louisian natural gas assets could fit very well with that coming out of the Haynesville. And then as you know, those wells come on can come on very strong, but have a pretty good decline on them as well. So it's kind of -- I think it's going to take all of them, but I definitely think permits probably going to take the bigger share of all that, but you will see coming on that. The area that's going to be interesting is you see anything coming out of Appalachia, can they get any more gas takeaway out of there? That's always been a struggle to get that happen. That would be the most logical place being gas reserves up there. It just has not happened from a regulatory standpoint to be able to get something to come down. But you will see. That's why I think Oklahoma is interesting because you're going to get more gas here on the gaster side, you still get some of the liquids out, you still get some oil that you get a lot more gas. That's what we really like that on that option on the Mid-Con.

The only thing I'd add about the Haynesville is if you look at how it's been in the past when we basically went from 0 LNG exports in to where we are today and say, 2024, which is, I think, last year, maybe 12 BC something like that today. Yet you have plenty of gas to put into those LNG exports. And what would happen is if the price of gas sort of rise, then rates would go into the basin. And you could track it. You could see how the rigs were directly corresponding to the gas price. Gas price fell, rigs go down. But I think with this demand that 10 Bcf a day, I do think it's going to take and have a little more consistency in the Haynesville area. Now what happens once you fill up another 10 Bcf, now maybe there's even more because there's more LNG facilities that have not been FID yet primarily in the Louisiana area. So we'll see what happens between 2030 and 2040. But I can see some positive news for natural gas in the next -- the last 5 years.

Are you guys looking at gas storage investments on your [indiscernible]?

We actually have 2. One is called is [ Gish ], Jefferson. We're actually recompleting and doing an expansion project out there right now. We have a 2 Bcf a day gas storage bill out there and they had a soft dump, which frankly, as far as gas storage goes, not that big. We're expanding that to 8. We can continue to expand that even more. We have a second soft dump area where we can expand just as high as the Gish stuff.So we can have a significant amount of storage out there. We do think that's going to be necessary just because when you're flowing that much gas, you have maintenance interruptions and you need somewhere to put it, and it's going to be valuable to do that.

Now, it's not like traditional storage is mainly in the rest of the United States, which is primarily driven by utilities and especially natural gas distribution utilities where they take up the space, they put basically gas in their ratably every single month, and then they take it out there in the winter because they have to have it because you have to have the additional volume to meet those peak demands. So you're not necessarily going to have all that peak demand stuff down there because of weather, but you can have it because of maintenance. And we'll see how that turns out. But we got two really nice locations down there that we're really -- we're excited about let's see what have.

That's where our growth is. We have other storage facilities throughout Texas and Oklahoma. So we're very familiar with the natural gas storage. We've expanded those after a winter storm Uri, we got a big uplift on those, and we expanded those out to their max capability as well. So storage -- natural gas storage has been a good tailwind for us for a period time.

Any other questions from the audience?

Okay. I'm going to wrap up just on NGL competition. So you have one competitor -- you had one competitor the proposed project, but we haven't really heard too much. How -- I guess, at a high level, how competitive do you think alternative options can be with the ONEOK system, which is very established on bringing NGLs from the Bakken to market? And how impactful do you see competition being to your business in the Bakken?

So what I say when we think about the Double H pipeline coming out of the Bakken, is that you got to go look at the competitive landscape in the Bakken. And right now, our G&P has about a 60% market share in the Bakken. That -- those NGLs are not going to go anywhere except for there continue to be recontracted. So you're really talking about competition on 40% of the basin. A lot of those gas plants out there today are contracted to us for a long period of time. So one gas plant is coming up next year is a Kinder Morgan plant. They had a pipeline that was -- that DAPL was taken over crude oil open pipeline. So they're bringing 18,000 barrels a day down that pie point starting next year. So we will lose that -- that's -- but that volume is going to go into a P66 line that only has a 6-inch pipeline only has about 20,000 barrels a day.

So we think that's very much going to limit the competition on that pipeline. So obviously, as our contracts on certain ones come up. Will we have some competition out there? Possible. It could be out there with to see what goes. It means we continue to go forward. But what I would say, we've done a very good job with a lot of our customers as they come up and need things we're going to be on that we typically never allow a contract completely come to the end, unless we have something like this one with Kinder Morgan where they had another alternative that they were trying to use on that. So I don't think it's going to -- besides we will lose this 18,000. Can it have a little bit of impact us? Possibly, but I don't think it's going to be a major impact on our system up there. We are very integrated with two highly systems that work very well together, and a lot of producers seeing the benefit of being tying in one customer that can take you all the way to the bottom instead of going to Kinder Morgan P66 and somebody else.

Great. Thank you very much, Pierce, Sheridan and Walt.

Appreciate it.

Hello again, everybody. For those who don't know me, I'm Keith Stanley. I run our Midstream group here at Wolfe Research. And I'm very happy to have ONEOK's senior management with us as well today. We have Pierce Norton, CEO; Sheridan Swords, Chief Commercial Officer, sorry, Sheridan; and Walter Hulse, CFO. So thank you all for joining us.

As I said in the last one, please feel free to throw your questions in. Just raise your hand and we're happy to have you participate in the conversation.

Maybe we could start just strategically with kind of a look back in time. The company has been probably one of the more acquisitive in the midstream space and roughly doubled the size of the company with M&A. So -- can you just talk through some of the strategic rationale on some of these transactions and how you're positioned looking forward if you expect to continue to be fairly acquisitive in the future?

So I'll start -- and Sheridan fill in on this. But I think our acquisitiveness actually goes back all the way to the early 2000s. We went through a period of time back there where we actually did quite a few acquisitions. The theory was is that you get yourself positioned acquisition-wise to expand and extend off those assets that you're collecting. So we did that and then we kind of went through a period of organic growth where we spent billions of dollars across the middle part of the United States, aggregating these different assets that we bought. And then we ran into a period here where we felt like that we needed to do more M&A on specific criteria. So we socialized that with the Board.

We came up this list of criteria that we're looking for. We created some questions around that. And before we did any sort of looking at companies, and then we started putting these companies kind of through this filter. And then that's where we ended up doing Magellan, we did Easton. We did EnLink, we did Medallion and several of these companies, we've actually done, I think, 5 acquisitions counting NGP in 2 years. So we're very pleased with where we are right now. We feel like we're back in a position now where we can continue to expand and extend. So they're good projects that we're doing these extensions on, but they're also complementary because they're contiguously integrated to the assets that we have. So we're in a position now where we can be very patient about what we do next. And our focus right now is on integration.

Pierce, I think I recall a time in the past where you said there was actually a list of companies that you identified as ones that you could add value to. Is that list now smaller today, would you say, on potential opportunities that make sense?

Well, I would say they're different because the list is it morphs because of what it is the criteria that maybe you have satisfied currently, but you still need -- see the need of doing some other things. So I'll give you a couple of examples. One of the things that we wanted to do originally back in 2021 kind of time frame, it took us until 2023 to get it done, but is to diversify -- try to diversify a little bit out of the Bakken into some other areas. We wanted to go into businesses that were more what we call demand pull instead of demand push and which kind of get from supply and demand is another way to look at that.

So having done that, we -- do we still want to diversify even more? Sure. But right now, expand and extend is our main focus. So as the criteria changes, so do the possibilities of the companies. But right now, we don't see anything out there that we can't be patient on. And so we're going to continue to do what we're doing, which is continue integration, continue to get through -- we'll talk about this probably in a little bit, but what is it that we need to do to prove to the market that we are -- we have the great assets that we have. So Walter, do you have any other comments on that?

No, I think that if you go back to that original criteria, we were looking for something that was going to be credit accretive that was going to give us scale. We clearly think that we achieved a couple of those and kind of took them off the list. And putting ourselves in a position, Pierce mentioned that we had spent a lot of capital growing the business originally. When we got to about a $4 billion mark in a 10-year period, we went from $1.4 billion of EBITDA in about an 8-year period to $4 billion. And then we saw that we really needed to do some things to reposition the business for the next couple of decades to get ourselves back in a position where we would have an asset base that we could expand and extend.

So we did the acquisitions that we've done. Now you look at some of the projects that have come off of that, like the Denver expansion of the refined products pipeline to feed the Denver International Airport. That's a perfect example of taking the new assets that we acquired and using our model of extend and expand into a new market and continuing to grow those assets off of an existing footprint.

And Pierce, I think you mentioned kind of convincing the market of the strategy of the acquisitions. What do you think the market is misunderstanding or underappreciating about the ONEOK story these days?

I think it's just how to model the business that has done 5 acquisitions in 2 years. I think that's the biggest thing because we have gotten very predictable. We still actually are predictable. It's just that once we go through -- we don't give quarterly guidance. We gave an annual guidance. And when you look at kind of what we printed in the first quarter multiplied by 4, you come up short of what our guidance was for 2025. So I think there was some skepticism there.

And as we went into the second quarter, we proved that, yes, second quarter is better than first quarter. We're about to print our third quarter numbers. You'll see what those are here shortly. So I think it's just a matter of proving to people here's what these assets can do together and seeing the different profile that these assets have together over a year and understanding what is it that changes from quarter-to-quarter that makes these earnings go up. And I think once we get through another couple of quarters here, I think a lot of that -- it's going to be well understood.

So with that backdrop, any commentary on how volumes have been tracking in some of your key basins relative to expectations through the summer months?

Yes. I mean, obviously, we always see an uptick in volumes through the summer months. We've kind of said for a period of time that the -- we get winter. I tell everybody, we get winter every year in the Bakken. So volumes do come off in the Bakken in the winter and it sometimes takes a little bit to come back on. Had a little bit winter weather earlier this year. And so our volumes are ramping to a level that we are getting back to where we thought they could get close to at this time of the year, a little bit delayed.

There has been a little bit of dampening of volume on some of the producers, but we're still growing, still look to continue to grow into the future as we point in the Bakken. The one that's really been kind of a surprise to us here, not just this year, but the last couple of years has been the Mid-Continent. There's a Cherokee formation over on the western edge of the state that there's 4 or 5 different producers out there that have really been leaning into that and been growing that area out there that has actually -- for a long period of time, I thought the Mid-Continent would be kind of flattish standpoint. But now we are actually seeing growth from that area as we continue to go forward out there.

And then the Permian is growing. We continue to grow in the Permian, continue to see those volumes come up, continue to hook up [ CDPs, ] continue to see the growth out of acreage that's been dedicated to us on the EnLink volume that continues to come on. So on the G&P side, all areas we're seeing growth even though admittedly a little bit tempered down from what we thought it would be when we had $75 crude oil versus $65 crude oil we're seeing today, but we still see good growth on that. And the NGLs kind of reflect that as well as we continue the we still continue growth across that.

Our growth out of the Bakken has been a little bit more better than it has been good this year versus the G&P, and that's because of our discretionary ethane. We've seen a bigger opportunity this year to bring more ethane out at wider spreads than we have in the past. So we've been be able to put a lot more ethane. So you get a little bit of uptick on that side of it as we continue to go forward. So overall, I think we're sitting in a very good spot heading into the back half of this year.

A little more color on the Bakken as it relates to winter. There's 2 factors up there. One is, a, it gets cold, everybody knows that, right? But a producer will turn on what's called a heater treater during the coldest part of the winter to keep the oil flowing, which is where they -- most of their economics come from. Well, that actually takes away because they'll take that off the tailgate of where they're producing from and actually use that in a heater treater. So it actually turns our volume down about 10%.

The other pieces are what is the severity of the winter events that you have. So the cold weather actually is not -- it doesn't move the needle as far as shutting in volumes or whatever, but a severe wind storm, ice storm, 4-foot snows that cover the road so that the producers can't get in there to service their wells. Those are the things -- those are the 2 main factors that happen in the Bakken.

Sheridan, any comments across your geographies on your expectations for 2026, understanding that producers haven't fully finalized their plans. Just assuming oil prices stay around where they are in kind of these mid-60 levels.

Yes. Where we see now in the producer activity in our -- in each one of our areas, we see -- in the Bakken, we see modest growth out there. On the gas side of it, there's enough activity to keep that going forward. Obviously, the producers, as you said, are in their budgeting time frame. Due to the quality of producers we have in that area, we really don't see them making a material change in what's going on in the Bakken. So we'll see -- we're really expecting to see some modest growth going into 2026.

We talked about in the Mid-Continent. As I said, we're very pleased on that side. The one thing I always think about the Mid-Continent is almost like an option that we have on gas prices. We continue to see more LNG come online, if we see any more uptick in gas prices, you could see some people in the Mid-Continent. I talked about the Cherokee but in the SCOOP and STACK come in and go to more of the gas part of that play, which still is pretty NGL-rich going forward.

The Permian is -- continues to be the Permian. I mean there's some people talking about there may be a little bit of slowdown on rigs in there, but we are seeing producers being much more efficient, drilling longer laterals, being able to get more out with less, and we still continue to see pretty good growth coming out of the Permian going forward.

Overall, we see crude oil being fairly flattish, around 13 million a day out of the United States. But you still have to -- even to maintain 13 million, you're going to have to drill. You're going to drill in different areas. And so we think the Permian is going to continue to grow at the detriment of some other areas and we'll be able to keep up with their declines. People won't drill as much as there, but we definitely think that Permian is going to be one that's going to take up a lot of the slack on the oil side, which will mean much greater gas coming out of the Permian.

So with the volume growth you expect, so the company has a target of mid- to upper single-digit growth in 2026 EBITDA. Can you walk through what is the basis for that? Volume growth sounds like you're expecting modest volume growth kind of across the system. How important are some of the capital projects that you're bringing on? And then how meaningful are some of the remaining integration-related synergies to your '26 growth?

Sure. Well, it is kind of a different story this year than it has been historically over the previous years where it was very volumetric driven by producer activity. Clearly, we are 90% volume times rate based on a fee. So that's our key business. But we've got a number of projects, some of them synergy related that are being completed right now and will be completed as we go into the balance of the year or in 2026.

Each of those kind of gives us an incremental stair step up. And a couple of examples. When we bought Magellan, we needed to connect our Mont Belvieu facility to the 3 distribution centers in East Houston. We were going to build a pipeline to do that. That was going to take us about 3.5 years. We had the opportunity to buy Easton. We bought Easton, but we still had to connect that to the other -- to all those entities. We're just now completing that kind of as we speak, and that now enables us to get that next wave of synergies out of the Magellan acquisition. And what it really is doing is it's providing us the opportunity to provide blend stock to not only our own assets, but to the customer assets at these various terminals out of our system.

Up until this point of 2025, that opportunity didn't exist. So we now see that kicking in, and it will go forward and through '26 and beyond. We were doing a very similar thing where we connected our Conway frac facility to Kansas City, Tulsa and Cushing to enable us to vastly reduce the logistics of blending around the Magellan system in the Mid-Continent. That's going to be completed here in the fourth quarter. So we'll see that full benefit going into 2026.

In 2026, we're going to complete the Denver project, where we're expanding the refined products line out to the Denver Airport. That's a fully backed project. There's enormous growth at DIA. And so that's been driven by jet fuel, but gives us an opportunity to serve all products because we can batch up that line. So that kicks in, in '26 as well. And then there are a number of smaller projects that we haven't even been out public with, but that are basically just taking either pinch points away or making connections. Another good example would be Medallion as we continue to make the connections to get Medallion volumes on to our long-haul crude pipes. We start to see that continue to fall in.

So those are the incremental stair steps. We're still going to see nice volume growth across our system. And typically, in previous years, that would be what really kind of drove growth. But here, we've got some stair steps that they're going to take us up.

I guess what would you say are the key risks to executing on that 2026 growth outlook and your level of confidence in it right now?

Well, I think that everything I just described is completely in our control. So I don't think there's a whole lot of risk. Most of it's in the later stages of completion from a construction standpoint. So I really don't see that as an issue. Clearly, with crude in the low 60s, we're going to need to see what producer activity is across all basins. To the extent that, that slows a little bit, that could have a volumetric impact that could slow the growth. We do think we're going to continue to get growth in each of these basins, potentially maybe not at the rate that we thought it was going to be.

So that to me is probably the biggest risk. But I think it's important to note that in '16 and in '20, when crude broke down into the 20s and in 2020, it went down to negative and came back up. When we were coming back up through the 40s, you would hear producers say, if we could only get to the 60s, we will coin money. Well, they got a taste of 75, 80, and that felt real good for all of us. I mean we all enjoyed that. My sense is that if we stay here in the 60s, that will go back to being the norm and they can make good money in the 60s, and they'll continue to press on. We have the benefit of having kind of the who's who of customers. Most of the majors or the large independents that are going to continue to drill through cycles. They want to maintain their crews. They want to continue to produce. So we don't expect them to really back off in this environment.

Any questions in the audience at all? Okay. I wanted to ask on the Sunbelt Connector project, definitely an interesting one that I think people probably weren't expecting. Big refined products pipeline that would run from El Paso, Texas to Phoenix. Just what you're seeing there as far as the opportunity level of customer demand at potential cost and returns for a project like that?

So really, when we think about the Sunbelt Connector, what we're seeing is that today, Phoenix is a growing market. It's growing from population, which is driving unleaded demand growth. And we're also seeing it growing from jet fuel as they expand their airport out there. Right now, Phoenix is fed by 2 pipelines. One pipeline is coming from El Paso into Phoenix, and that one is full. And the other one is coming out of California into Phoenix as well. And as we see rationalization of refineries in the California area, we see that more and more of that refined products is going to want to stay in California. I say we and that's a lot of the people we're talking to share this point of view on going forward.

So we see an opportunity to be able to a line into Phoenix and be able to bring in not only refined products from the Gulf Coast through our system, but also from completely in the upper Midwest as well. And we've had people talk to us about being able to put on the system. So -- and definitely with the administration that we have in there right now, we think we have a unique opportunity to be able to get a pipeline like this in. And we saw enough interest as we talk to different people and done all the scoping and everything else to go out and do a binding open season. So we have a 2-month open season that we're talking to people and getting commitments and what that's going to be.

On the cost and return is what we have is we've looked at under many different scenarios of how much people would sign up for. And depending on what they sign up for is going to drive what the capital cost can be. So we have some different scenarios where -- depending on where it is, larger or smaller, what capital we can put in there to go ahead and get this pipeline in, either put into a case where we could ramp up to it or put some optionality into it or upsize it a little bit in the beginning.

So we really need to see what comes back from our customers and how much they're willing to sign up. We'll really tell you how what the capital is going to be on that. It will be -- we talk about, we think it will be a very nice return on this project. One is we will put a little bit bigger pipe in the ground. We've already said we're going to put a 24-inch line from El Paso to Phoenix. And that -- what we don't need, we've not seen the demand from our customers for a pipeline that big. One thing is if we get a lower level, we won't have to put any pump stations on that, so you won't have any power cost. It will be very easy to move it out there. But putting that bigger pipe in gives you the opportunity to expand it into the future.

If you continue to see more rationalization in California or continue to see growth and you need more pipeline capacity and then we kind of see it as a onetime shot to be a pipeline in there. We want to be able to put additional pumps on there and to be able to expand the capacity. And if you do that as we've done on other pipelines, then the return on the project would be very, very nice.

And what's the time line and permitting look like on a project like this? I think we all know what a gas pipeline project would look like, but what does it look like on...

So on the liquids side, you don't have to go through the FERC process. You still have to go through the EPA and the Corps of Engineers and typical process they have to go through on any pipeline. But what we are seeing at this time is on some of our other projects that we are doing, whether or not that be the Denver expansion or our Texas City export dock is that we are getting permits a lot quicker than we were in the past. And so that time frame is really being shrunk down. So right now, we think it's under 2 years to get permitted.

Okay. And then about a year or 2 construction?

Right.

On CapEx, so it's a little -- I mean the company is $3 billion of CapEx this year, growth CapEx. What's interesting about ONEOK is you're actually still kind of like free cash neutral-ish at $3 billion of growth CapEx, whereas a lot of your peers are free cash negative in the current spending levels. How are you thinking about CapEx over the next few years for the company? Are you looking to really grow faster and potentially keep up $3 billion or higher of CapEx? Or is this going to turn into more of a free cash flow and capital return type of story?

Yes. No, we won't continue at that $3 billion. Next year, just given the carryover of the projects that we have, we'll likely be close to around where we are this year. But as you move into '27, '28, '29, we're going to see that tail down.

Clearly, the Sunbelt Connector, if it was to come on as a large project, -- but we think that if we move forward with it because we get the appropriate contracting, we'll likely have a partner in that or we'll utilize project financing. So we won't take that fully on our balance sheet as we have in the past with some of the pipes.

So I would expect to see a meaningful step down in CapEx as you get out to '27, '28. And that actually is interesting because it comes in at the same time that the new Big Beautiful Bill is going to give us the tax savings. We're going to have about $1.5 billion of incremental cash flow from tax savings because we're going to be able to utilize 100% bonus depreciation, which will move us out to not being -- we'll still be at that kind of no tax rate type of environment through '28, and we'll start to go up to the AMT in '29, which is 2 years later than we thought it would be.

So on the balance sheet, I think your target is to get to the 3.5x debt-to-EBITDA by the end of next year. So not quite there, but with clear visibility to get there. How do you think about stock buybacks right now? Because the stock valuation, in my view anyway, has gotten very attractive at this point, but you're still a little bit above the leverage threshold of where you want to be. So how are you weighing that? And how much flexibility do you have for buybacks?

Yes. Well, we clearly -- we're focused on getting that leverage down. We've cash called, I think, 4 of the last 6 bonds that have come due. And as we get more visibility, clearly, we -- our flexibility around stock buybacks increases. We are in a position where Moody's wants us to be at 4x for mid-BBB or Baa2. S&P wants us to be at 3.75. So our target is actually more conservative than the agencies.

So as we get to that 3.6 -- and that's a 3.6 run rate at the end of next year. As we get visibility of that, we do have some flexibility. If we were to delay that ourselves because of some actions we took and still kind of got through the rating agencies benchmarks, we'd be fine. So I don't think anything that we would do necessarily change the trajectory of that reducing credit metrics. So our flexibility is increasing.

I wanted to ask about ethane and the market overall because the one thing that strikes me, you have still a fair amount of unrecovered ethane in some of your regions that you could benefit from. And it feels like we're getting a step change with some of the export projects just in terms of ethane demand in the U.S. If you look at EPD's Neches River project, Energy Transfer Flexport, it's a pretty meaningful step-up in total ethane demand in the country. How do you think that plays out in your regions as far as ethane recovery over the next few years? Are you expecting to have more opportunity to recover more ethane and ship it down to the market?

Yes. I definitely think there's going to be an opportunity. I think it's really going to come into the Mid-Continent range is where it is. We've always said that we think the Permian is always going to be an ethane recovery. The Bakken is always going to be an ethane rejection unless we decide to bring some ethane out on our integrated system. And so really, the Mid-Continent, we've always said it's going to be in and out of that.

So the thing you have going is they bring those projects on, they're going to increase demand, that's going to increase the price of ethane spread it out. We should be able to give a little bit more in, you got to balance that with is how much more growth is going to come out of the Permian. The Permian grows more, that's going to bring more ethane on, so there's a balancing effect in there that's going to happen to support. But overall, you're right, it's very positive for us on the ethane that we're not extracting today at full rates and that's going to happen in Mid-Continent.

Would you ever consider ethane export projects yourself? From what I understand, the international demand is pretty high, but it seems like your path to exports has been to do it in a more brownfield way? How are you thinking about ethane exports?

So one thing we've looked at ethane exports for a period of time, just like we looked at LPG exports for a period of time. One thing we found out is that on the ethane exports, any export is beneficial to us. This as you said, because it increases the price of ethane increase the pull of ethane. If that pulls that out of the natural gas stream, we're going to get the pull-through effect on our system. So it doesn't necessarily have to be our ethane exports.

The thing that has got us a little bit is just the period of time we were looking at it, most of these ethane exports are going to China. And that's something that becomes a little bit more difficult to wrap your hands around, which is much different than in LPG exports where we want to make sure our product moves across the thing. You don't -- when you're dealing with propane, propane has to come out of the gas, ethane, we at least have the toggle that you can't find a home for ethane on the NGL side, you put it into the natural gas -- we do have a way to clear the product. But we're very supportive of the 2 ethane projects coming on, and we think it will have a positive effect to us just how much, we'll wait to see.

The one thing I've been thinking about more just with, I mean, the LNG market right now and all these projects getting sanctioned, it's almost becoming a little overwhelming the amount of gas demand we're going to see from all the LNG, especially if it runs at full utilization in the early 2030s. How is the company positioned to benefit from this, whether it's the Louisiana gas system or even maybe a little more far out kind of concept of some of these basins like the gas areas of the Mid-Continent or the Barnett, are we going to see a call on some of those areas where your infrastructure might see greater utilization because of all the gas demand on the Gulf Coast?

Yes. Definitely, as you think about Louisiana, Louisiana, we are tied into some of the LNG down there today. We kind of see ourselves as the last mile in that area, and we do see some of the new projects coming online will be in Louisiana. So we're already taking advantage of that and growing on that side of it, not only for the LNG demand, but we're also seeing it for industrial demand around the river corridor.

So we're very excited about Louisiana and that was one area when we bought EnLink, we didn't put a whole lot of money and -- a whole lot of value on the Louisiana natural gas assets, and that's been a really big surprise for us as we've got in there, we've really seen some opportunities to be -- we see that as a demand pull. Louisiana is a demand pull to us on our system on the LNG. But we didn't -- when you think about it, all that demand coming online, another 10 Bcf coming online is going to have an effect on the natural gas price as it comes up.

And we think in the Mid-Continent, we've always had an -- I always thought of it as we have an option on natural gas. If the natural price gets up, you're going to see more people want to move into the gassier part of the SCOOP and the STACK more in the central part of the state and to produce that higher gas value because you can get some pretty big gas wells coming out of that, that still are pretty rich in NGLs. So we definitely think as this keeps coming online, you'll see be more pull out of the Mid-Continent as well.

And then definitely, the Permian is going to have to carry the load on a lot of this coming out, see more demand -- more as prices rise, you're going to see more drilling into the Delaware. Delaware is a much more gassier area. Wells come on with a lot more gas, more of the return comes on the gas side. So we actually see there will be more coming out of the Permian, definitely in the Delaware. So we think that LNG is going to have an impact on the system as we continue to look out as these 10 Bcf of projects come online.

You announced that you get some dry gas drilling too...

Yes. I do think you'll get some dry gas drilling. I think Haynesville could be very much very close to Louisiana, and that's where our Louisiana natural gas assets could fit very well with that coming out of the Haynesville. And then as you know, those wells come on very -- can come on very strong, but have a pretty good decline on them as well. So it's kind of -- I think it's going to take all of them, but I definitely think Permian is probably going to take the bigger share of all that, but you will see coming out of that.

The area that's going to be interesting is you see anything coming out of the Appalachia, can they get any more gas takeaway out of there? That's always been a struggle to get that happen. That would be the most logical place, big gas reserves out there. It just has not happened from a regulatory standpoint to be able to get something to come down there. But you will see -- that's why I think Oklahoma is interesting because you're going to get more gas here on the gassier side, you still get some of the liquids out and you still get some oil, but you get a lot more gas. That's why we really like that option, that option on the Mid-Continent.

The only thing I'd add about the Haynesville is if you look at how it's been in the past when we basically went from 0 LNG exports in 2016 to where we are today in, say, 2024, which was, I think, last year, maybe 12 Bcf or something like that a day, you had plenty of gas to put into those LNG exports. And what would happen is if the price of gas would rise, then rigs would go into the basin. And you could track it. You could see how the rigs were directly corresponding to the gas price.

Gas price fell, rigs go down. But I think with this demand of that 10 Bcf a day, I do think it's going to take and have a little more consistency in the Haynesville area. Now what happens once you fill up another 10 Bcf, now maybe there's even more because there's more LNG facilities that have not been FID-ed yet, primarily in the Louisiana area. So we'll see what happens between 2030 and 2040. But I can see some positive news for natural gas in the last 5 years.

Are you guys looking at any gas storage investments on your system to help...

We actually have 2. One is called [ JISH, ] Jefferson Island. We're actually recompleting and doing an expansion project out there. Right now, we have a 2 Bcf a day gas storage field out there in Salt Dome, which, frankly, as far as gas storage goes, not that big, but we're expanding that to 8, we can continue to expand that even more. We have a second Salt dome area where we can expand just as high as the [indiscernible]. So we could have a significant amount of storage out there.

We do think that's going to be necessary just because when you're flowing that much gas, you have maintenance interruptions and you need somewhere to put it, and it's going to be valuable to do that. Now it's not like traditional storage is mainly in the rest of part of the United States, which is primarily driven by utilities and especially natural gas distribution utilities where they take up the space. They put basically gas in there ratably every single month, and then they take it out during the winter because they have to have it because they have to have the additional volume to meet those peak demand.

So you're not necessarily going to have all that peak demand stuff down there because of weather, but you can have it because of maintenance. And we'll see how that turns out. But we got 2 really nice locations down there that we're really -- we're excited about. We'll see what happens...

That's where our growth is. We have other storage facilities throughout Texas and Oklahoma. So we're very familiar with the natural gas storage. And we've expanded those -- after Winter Storm Uri, we got a big uplift on those, and we expanded those out to their max capability as well. So storage -- natural gas storage has been a good tailwind for us for a period of time.

Any other questions from the audience?

Okay. I'm going to wrap up just on NGL competition. So you had one competitor -- you had one competitor proposed a project, but we haven't really heard too much. How -- I guess, at a high level, how competitive do you think alternative options can be with the ONEOK system, which is very established on bringing NGLs from the Bakken to market? And how impactful do you see competition being to your business in the Bakken?

So what I'd say when we think about the Double H pipeline coming out of the Bakken is that you got to go look at the competitive landscape in the Bakken. And right now, our G&P has about a 60% market share in the Bakken. That -- those NGLs are not going to go anywhere except we're on to a ONEOK NGL pipeline. That's continuing to be recontracted that. So you're really talking about competition on 40% of the basin. A lot of those gas plants out there today are contracted to us for a long period of time. The one gas plant is coming up next year is the Kinder Morgan plant. They had a pipeline that was -- that DAPL was taking over crude oil open pipeline. So they're bringing 18,000 barrels a day down that pipeline starting next year. So we will lose that. That's competition. But that volume is going to go into a P66 line that only has a 6-inch pipeline, only has about 20,000 barrels a day.

So we think that's very much going to limit the competition on that pipeline. So obviously, as our contracts on certain ones come up, will we have some competition out there? Possible. Could be out there. We'll have to see what goes as we continue to go forward. But what I'd say, we've done a very good job with a lot of our customers as they come up and need things, we're going to be extending term on that.

We typically never let a contract completely come to the end, unless we have something like this one with Kinder Morgan where they had another alternative that they were trying to use on that. So I don't think it's going to -- besides we will lose this 18,000. Could it have a little bit of impact us? Possibly, but I don't think it's going to be a major impact on our system up there. We are very integrated with two highly -- systems that work very well together and a lot of producers see the benefit of being tying into one customer that can take you all the way to the bottom instead of going to Kinder Morgan P66 and somebody else to frac it.

Great. Thank you very much, Pierce, Sheridan and Walter. Appreciate it.

Thank you. Appreciate it.

Good afternoon, everyone. My name is Theresa Chen, and I'm the Midstream and Refining analyst here at Barclays. It is my pleasure to introduce our next company, ONEOK. Joining me from ONEOK are President and CEO, Pierce Norton; CFO, Walter Hulse; Chief Commercial Officer, Sheridan Swords. Welcome, everyone.

Thank you.

So as ONEOK works to integrate all of its recently acquired assets, progress on the synergy targets and 2025 guidance remains a key focus amongst investors. I want to start there. Can you talk more about where ONEOK is currently tracking with respect to the goal of the $250 million in synergies in 2025? And have your expectations relative to the synergies changed at all since initially putting forth this guidance.

Well, no, our expectations haven't changed. I think, if anything, I think you got to put it into buckets. The one that we're furthest along on is our Magellan acquisition. If you think about it, Magellan, we bought in September of '23. So we had kind of the fourth quarter to get things set up and we hit the ground running and had all of '24 and now we're into '25. Most of those opportunities were opportunities that were completely within our control. So at this point in time, I think we're well ahead of our expectation as it relates to Magellan and really pleased with the opportunities that have presented themselves that we didn't know about and we're pursuing for further synergies.

When you look at EnLink and Medallion, I'll break those apart too. Medallion, again, almost entirely within our control on the synergies. We are in a position where we can fill our 2 long-haul pipes. We can actively go out and gather that crude and use the Medallion system in a more aggressive way than it was being able to be used before. to fit in with our long-haul crude assets that we bought from Magellan.

Then EnLink, we just have really been at it since February 1 when we closed that acquisition. And in that one, we're well on our pace on all of our corporate synergies. They're kind of falling right into line. Some of those big ones that come off are insurance, for example, those don't happen the day you close the transaction. They happen throughout the course of the year. In fact, we just found 4 different policies on September 1.

So those are types of synergies that we will now pick up from this point going forward in perpetuity. The low-hanging fruit in and around EnLink is all happening right away. But things like contracts rolling off that are synergies, those just happen with time. But we're on pace, and we're fairly comfortable with the $250 million.

Well, the only thing that I'd add to that is that there wasn't a lot of capacity left in the processing side on EnLink. So some processing plants needed to get built. So you don't do those overnight. So they take sometimes a year or 2 years to build those. And so that's going to be -- that was another thing that we knew that the pace of the synergies in EnLink would be different than in Magellan just because of either the contracts terminating or the fact that we got to build things.

And I think you see us come out right away. We've already sanctioned another plant into the Delaware to get that capacity coming on as quick as we can. And then there, we have a plant coming along at the end of this year, the Shadowfax plant in the Midland that will give us capacity to be able to grow, as Pierce said, and we'll see those synergies continue to go forward.

We did have capacity in the Mid-Continent, and we're now connecting our legacy ONEOK system and the legacy EnLink system together that we can now access the most efficient capacity in the Mid-Continent. So we can direct the gas to each one of the respective companies processing plants to make sure we get the most liquids out of each plant. And all those plants are connected into our NGL system.

I don't want to beat this question to death, Theresa. But in the Mid-Con, what's important there is that there was area dedications to the EnLink plants. And that dedication was far outside where the assets were located. So a lot of times when the producer went to drill a well, then they had the right to go out and get it, but it was too far to economically drill. What just so happens those acreage dedications overlap our assets, the old ONEOK assets. And so now instead of losing that particular package to somebody else, we are now able to pick it up because of the expansiveness of our footprint between the 2 systems of EnLink and ONEOK.

Perfect. And on this type of optimization opportunities to capture more volumes and market share, but as it relates to the interplay of NGLs and refined products, in particular, can you provide any data points to quantify those types of opportunities?

Well, if you think about on optimization between the NGL and the refined products system, one of the big things that came out right away and said that you can move NGLs on a refined product system and you can refine products on an NGL system. And that really came down to being able to reduce the cost of butane getting to the blending location. We blended over 50 locations across our refined products and asset base. And a lot of that is being trucked to those locations with us being able to put in -- be able to use the assets together to be able to move a lot of that volume off the truck onto pipelines and get it into further out into the system where we can blend more.

Magellan's typical cost was $0.20 a gallon to move butane to the blending locations. As we finish the Easton integration, Easton connections, we finish connecting our Conway NGL hub into the Midwest refining pipelines that we have, and we continue some of our other blending projects. We'll move that $0.20 per gallon on the logistic cost down to $0.10 per gallon in 2026. So a substantial reduction in cost.

And then we'll continue as we get into '26 as we bring on the Denver expansion, we'll be able to use that as well to be able to move butane from the Mid-Continent out to Denver to be able to blend there as well with that is now being trucked today. So we'll see a further savings into '26 into '27 as well. So we're seeing a great reduction in our logistics cost, which doesn't depend on a spread to be able to capture. That's just purely drops to the bottom line.

Got it. And how have customers responded to your ownership and operatorship of recently acquired refined products and crude assets over the past few quarters. What has surprised you in your commercial discussions?

I don't know if there's been a whole lot of surprises. I mean, ONEOK has always been a very customer-centered company that wants to make sure we take care of the customers. I think we have brought a little bit different kind of offering to the customers on the refined products side that they appreciate. We've also brought the willingness to spend capital -- more capital than we did before, and we've been able to work with our customers, especially like on the Denver expansion, where people were wanting that to be able to be done.

We tried to see what the opportunity was, how big that could be, what the future could look like and working with those customers to get an acceptable project out to the Denver and a very attractive project out to the Denver Airport with a lot of expandable upside onto that. So the customers have been very willing to work with us, been very -- see that ONEOK is customer centered. And I think they've liked as we've seen, like what they've seen so far because they continue to sign up for more volume.

Very good. And I do want to touch on the Denver refined product infrastructure project in a bit. But with recently completed and soon to be completed projects entering into service, ONEOK is set up with significant amount of operating leverage going forward. Can you speak to the opportunities that this provides you and how you see these assets such as the Elk Creek and the West Texas NGL pipelines contributing to future earnings and commercial opportunities.

So to go back, when we did both the West Texas expansion and the Elk Creek expansion, we had contracts behind that, that gave us a very acceptable return on those projects. But we didn't have to fill the complete pipeline up to get to those returns. So we oversized to put a little bit of optionality in there that we could put more volume on there than what was needed for the project.

So basically, you could think about that as we have free capacity. It's already been paid for, for certain contracts. So we sit there and go out there in the Permian, which is a very competitive area. When we compete, we can be very effective in competing for new volume coming on there that we can still continue to grow our bottom line. So our objective now is to go in and fill that capacity, both that we talked about on the West Texas pipeline and out of Elk Creek, but we also have the Medford fractionator coming up in 2026 that it's another one where it's a very low-cost fractionator. It's not completely full. We only needed to get a certain amount of volume into it contracted before for an acceptable return. We have FID-ed that when that comes up in late 2026, we'll be able to not only provide transportation out of the Permian, but also fractionation and be able to compete with anybody out there for that volume.

So the only thing I'd add to that, Theresa, is that when you make a decision on a pipeline, let's say you're going to build a 16-inch and you decide to do a 20 or 24, that extra cost to get that extra volume is very, very efficient because your right of way is going to cost the same, whether or not you put a 16 or 20 or 24. The ditch size is basically the same. So you're really digging the same level of ditch, the cost on that. So really, the only difference is the additional welding that you have on the pipe and then whatever the pipe cost is set between it. But it is very, very efficient to get extra capacity. The reason I'm saying that is because it doesn't take very much volume to really juice the returns on that extra capacity.

We like to say it's a lot easier to put -- to expand the pipeline by 2 inches before you put it in the ground and then after you put it in the ground.

Fair enough. And I'm seeing this playbook translate to my next question about the Denver expansion as well. There's some consistency here. So looking at this project coming into service next year, okay. So entering initial service mid-2026 at 30,000 barrels per day. Can you offer some more color on the strategic importance of this project. Sheridan, you touched on the butane piece earlier. Can you talk about the potential changes to PADD 2 and PADD 4 refined product movements. And how should we think about the time line to potentially scale the project towards its total hydraulic capacity of 250,000 barrels per day.

So first talking about the strategic side of it is that our refined product system is a demand pull system. So we want to be connected to growing demand anywhere across our system. And we're seeing growing demand in PADD 4 and in parts of PADD 5, not all parts of PADD 4, but definitely all parts of PADD 5. But definitely PADD 4, we're seeing growing demand in there and definitely, at the Denver Airport as they continue to expand that airport.

So we wanted to make sure we had capacity into that area that we could service that demand that we can pull it from our refiners, not just in PADD 2, but also in PADD 3 to be able to pull that refinery as we go forward. As we go and look at just the structure out there, what's happened, we sized it that we could grow as that area grows. And also, we sized that if there was a structural change in PADD 4 and refining capacity, we would be able to supply the front range with enough refined products to meet their needs continue to go out.

But even beyond that, we're even deeper into PADD 4. We're seeing premium markets continue to grow as more population grows out there as well and into PADD 5 on the eastern side of PADD 5 that this pipeline is set up very nicely. It's connected to all these other pipelines. As demand continues to grow, we'll be able to supply it out of the Mid-Continent and in the Gulf Coast.

And if there's ever any reason why the supply should be short out there in the Denver and the Front Range area, we're right there ready to add pumps on to this pipeline and fulfill that entire need.

It's 30,000 barrels a day, but it could easily -- with pumps, it could go over 200,000 barrels a day.

So standing ready to add pumps and with a potential long-haul tariff from those far-flung refining centers.

Right. And you said when could we see it grow. We'll see how -- what the market comes to it. It was -- as Pierce said, to make that pipe to grow it up to 16-inch or what we wanted was very small incremental capital to be able to do that. And when you look at the whole scope of the project, it gives us tremendous upside as things happen into the future. Same thing we did, we did the same thing with Elk Creek. We had a very -- we at the time, didn't think we needed a 20-inch pipeline, but we put a bigger pipeline in case we need it, and now we need it, and it's been very profitable.

Got it. So turning from the downstream side of things, let's go to the wellhead, okay. Producer activity has been an area of interest given the ebbs and flows of pricing out there. How are production and G&P volumes currently trending across your areas of service. And what are you hearing from your producer customers in terms of expectations for the remainder of this year and into next year?

Well, we're having the same dialogue we've always had with the producers we can going on. And as we think about '26, they're working through their budget processes at this time and it'll be later in the year when we get a little bit more insight of what they see into '26. Across our basins, we're continuing to grow. All basins are growing. Our volumes are growing up there. No doubt, growth is -- that rate of growth has slowed just a little bit as we kind of look across our system, but we still very much are growing our volumes, and we anticipate that to be into 2026 as well as like I said, we haven't got the official budgets and what they're going to do. Our producers are going to do in 2026, but everything they're telling us now, they continue to expect it to grow.

Obviously, the Permian is going to be one that's going to probably have the highest growth as well. But we're seeing good growth out of the Mid-Continent over on the western side of the state. There's the Cherokee formation over there. We've got copper producers continue to be excited about that location. And then the Bakken is going to be the Bakken. It's going to be a steady growth. It's going to be a low single-digit growth, especially with -- kind of more -- we're calling for more flattish crude oil, and then we'll see a lot of the growth coming through the GORs.

Perfect. And speaking of GORs and following that Y-grade molecule downstream. So can you shed some light on your outlook for NGL pipeline and fractionation economics as contracts turn over and incremental capacity is set to enter the market.

I think you have to look at it by region and what regions you're talking about. You can't just say you look at every -- not all regions are the same. But a lot of that incremental capacity you're talking about is definitely coming out of the Permian. As we said, Permian is a very competitive area out there. We are now on both pipeline and fractionation. We are at rates that are below new build economics. So we don't think there will be any at these rates any more additional being brought on at this time.

So I think with the assets we have out there, we will be able to compete at this level. But we see that kind of tightening up as more volume comes on. So we think we're more and more at a low spot right now coming out of the Permian as well as the Mid-Continent is, I think it's going to be steady as well. And obviously, out of the Bakken, there's been a lot of talk about a new entrant into the NGL space out at Bakken.

Never heard of it.

Yes, I thought you hadn't. And when I talk about the Bakken and the competitiveness in the Bakken, I first start off with and say that ONEOK on the G&P side when you talk about competitiveness on the NGL side. On the G&P side, we own 60% or have market share of 60% of the market in the Bakken. That volume is not going away. So first thing we talk about competitiveness, you can take 60% away. So now we're talking about 40% left that's up for competition. Of that, most of that, we have long-term contracts that go into -- well into 2030 on that volume. So now we're really talking about a very small amount of volume that's really up for competition in the near term into the Bakken.

So we like the position that we are in today as we can be able to compete in that area. We've known that this possibly could happen, and we've been preparing for it by extending contracts and keeping our contracts way out in front of us, be able to provide our producer with a very good service. They like what we provide up there. We've actually put extra capacity up there to be able to meet their needs and to be able to -- as some of our plants go down, we can move that volume to other plants. So we've had plants go down, our producers don't even know they go down. So through great customer service, moving our contracts out and our market share on the G&P side there, we think we're in a very good position in the Bakken as always.

Just as important is you're being able to take the gathering and the processing, the NGLs, the gas takeaway, all that's bundled into one service, and it gets you all the way from the -- where the supply is all the way to where the demand is, all the way down to the Gulf Coast. Nobody else has that kind of connectivity unless they go through multiple pipes. So it's just easier to do business with us, and it's an area where we can be way more competitive.

And you don't have the rate stacking as you go through different companies.

Fair enough. The integration, the connectivity and the redundancy and complexity of the system keeps that producer on. So also on the Bakken in terms of the ethane incentivization prospects. So in light of ongoing commercial efforts to construct another residue egress pipe in Bakken, how do you think the addition of incremental residue capacity could impact ONEOK's incentivized ethane extraction business in the region?

Let me try on this one. I like this question, Theresa, because I have a long history with Northern Border through other companies. And so everything on the gas pipeline takeaway side is kind of hinging not necessarily on volume, but what is the BTU spec that, that pipe can take. So the only way that actually any sort of things change up there in that area as far as gas takeaway, the egress of the gas, is if the BTU spec on that pipe were to be different.

So what I'm saying is that if that spec were, say, 1,200 Btu instead of, say, 1,050, then that would make a difference and start to do some things with your ethane rejection because you could leave more ethane in the pipe and then put it in there. But it's always going to compete with whatever the gas price is. up there in that area, in the Ventura area and the AECO area. So that's what really toggles the ethane rejection or recovery up there. But in the event that there's a pipeline built, and it just happens to go to a location that the Btu spec can be up to 1,200, which is pretty rare. But if that were the case, then that would start to have some effect on that. But we think in any way possible, it will be positive for us because we're the ones that toggle that.

Great. And looking ahead, I'd like to now turn to your JV export dock with MPLX. So as other industry participants point to challenged margins, how does this impact your expectation for the export dock if at all.

Well, the first thing we've always said that we have the volume behind that export dock going through our system today. So we have the supply for that dock. It's not like we need to go out or contract with supply, and that's already been done. Obviously, it's a competitive market. The export docks have never been that -- as good as some of the other projects that we've had in terms of return. That's why it's took us 10 years to get to this point as we continue to go forward. We see that export dock really as a further integration of our value chain. It's the completion of the wellhead-to-water strategy that we had and that a lot of our customers have been talking to us about is getting that -- making sure our product moves through the system.

So there's been a little bit of compression of rates. We have that. But our expectations are still -- as we look 3 years out from now, a lot of contracts now are short term, 3-year term, 3-year terms are fairly standard. We are still excited about what we see in the future about this dock and what it will do for us. It's still in a superior location. It's well right next to open water. It's probably 20 hours worth of travel time out and back from other locations.

And remember, on the shipping business, they have 48 hours from the time that ship is ready to load to move it up the ship channel, load it and move it back out of the ship channel. And when you're taking up almost half of that on the move and not the loading, it can be a great disadvantage, especially if you get fog or something else in there. So we think our -- and our customers are talking to us. They love the spot that we're in. We think they think it's actually worth a premium on that side.