ONEOK Aktie

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

At this time, I'd like to turn the conference over to Megan Patterson, Vice President, Investor Relations. Megan, please go ahead.

Thank you, Anna. Welcome to ONEOK's Third Quarter 2026 Earnings Call. Our earnings release and presentation were issued after market close yesterday and are available on our website. On our call today are Pierce Norton, President and Chief Executive Officer; Walt Hulse, Chief Financial Officer; Randy Lentz, Chief Operating Officer; and Sheridan Swords, Chief Commercial Officer.

Following 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.

Thank you, Megan, and good morning, everyone, and thank you for joining us today. Yesterday, we reported strong third quarter results, supported by our record Permian Basin volumes and continued growth across our integrated system, and we increased our 2026 financial guidance for the third time this year. We also completed several strategic milestones.

During the quarter, we closed a $9 billion minority equity investment, extinguished nearly $5.5 billion of debt and received credit rating upgrades from both S&P and Fitch. Earlier this month, we closed the acquisition of Brazos Midstream's Permian Midland Basin assets. Together, these actions give ONEOK greater scale, greater financial flexibility and clear visibility into the future earnings growth. Our confidence in ONEOK's outlook continues to gain momentum, supported by the assets that we own, the customers that we serve, growth projects already underway and the innovation of our people.

We're not providing 2027 guidance today, but we expect to do so after our fourth quarter results in February. But the underlying drivers are increasingly clear. Constructive producer development plans and continued drilling and completion efficiencies, recently completed projects that will contribute to full year's earnings in 2027, additional projects nearing completion and a full year of ownership of the Brazos assets. Importantly, that visibility extends across our integrated system and isn't dependent on a single commodity or project or basin. We see opportunities across natural gas, NGLs, refined products and crude and supported by domestic and international demand and the connectivity that we built across our value chain.

That diversification gives us a multiple of avenues to grow and capture value as the market conditions evolve. The broader backdrop reinforces the opportunity. Global energy markets remain dynamic, but growing natural gas demand for power generation, industrial loads and liquefied natural gas exports to feed the international demand all point to the same need, reliable access to essential energy when and where it is needed. International buyers are increasingly seeking long-term access to U.S. supply for its reliability and resiliency and a trend we're seeing through the strong export demand across our system.

These drivers also reinforce our confidence in our mid- to high single-digit adjusted EBITDA growth target for the next 5 to 7 years from our 2025 base. Brazos adds substantial contracted growth and value chain opportunities across our system, increasing our momentum toward the higher end of that target. ONEOK has the assets, the financial strength, the discipline and the people to capture the growing energy demand and to deliver sustainable long-term value for our investors.

With that, I'll turn the call over to Walt for a financial update.

Thank you, Pierce. Third quarter net income attributable to ONEOK totaled $1.35 billion or $2.13 per diluted share, and adjusted EBITDA totaled $2.24 billion, a 6% increase compared with the third quarter of 2025. Net income and EPS included a $336 million onetime noncash income tax benefit related to the corporate reorganization completed in connection with the minority equity transaction. Adjusted EBITDA included a $53 million net benefit from the transactions, primarily related to gains on the extinguishment of debt. As Pierce mentioned, we increased our 2026 financial guidance again, reflecting strong year-to-date performance, visibility into the remainder of the year and the addition of the Brazos Midland assets.

We now expect a 2026 net income midpoint of $4.18 billion and adjusted EBITDA midpoint of approximately $8.55 billion. This represents a $200 million increase in our adjusted EBITDA midpoint compared with the guidance we provided last quarter and a $450 million increase compared with our original February guidance. Of this quarter's $200 million increase, approximately $50 million reflects transaction-related benefits I just described. Approximately $75 million reflects the expected 2026 contribution from the Brazos assets, which is offset then by $25 million of transaction costs, and the remaining $100 million reflects stronger performance across our base businesses.

This year, we've been somewhat conservative with guidance due to the geopolitical volatility. If commodity conditions remain consistent with where they are today, we will have a very good tailwind in the fourth quarter and into 2027. That takes me to our hedging program. As the back end of the commodity forward curve has risen throughout the year, we've increased our hedging position into 2027 at a greater percentage and at higher prices than 2026. We continue to programmatically hedge commodity exposures.

On capital expenditures, we stated on the second quarter earnings call, we expected to approach the high end of our guidance range or $3.2 billion. We now expect 2026 capital expenditures to total approximately $3.5 billion due primarily to $200 million of capital associated with the Brazos acquisition, along with added growth projects such as the Cutter 2 plant, our Delaware NGL expansion and compression pulled into '26 from '27 due to Bakken and Mid-Continent activity levels. From a balance sheet perspective, we extinguished nearly $5.5 billion of debt in September, following completion of the $9 billion Apollo minority equity investment. Both S&P Global Ratings and Fitch Ratings upgraded our credit ratings to BBB+ with a stable outlook following these transactions.

With these actions complete, we are operating with a stronger balance sheet. And now I want to spend a moment on our leverage framework because it's an area we've received a number of questions. Our debt-to-EBITDA target going forward is approximately 3.25x or lower, and the lower matters. This is not guidance. It reflects a change in philosophy. We intend to operate the company with lower leverage than our previous target of approximately 3.5x. As modeled today, we would expect to go below 3x within the next few years. However, our commercial team continues to find highly attractive projects, which we expect will increase our capital expenditures over the next few years. We now have the financial flexibility to execute on those capital expenditures and still maintain a strong balance sheet.

We now view 3.5x as the upper end of our targeted leverage range. The gap between where we expect to operate and that ceiling is intentional. It gives us meaningful flexibility through business and commodity cycles and the capacity to act if a compelling opportunity comes along that clearly meets our return thresholds. That's optionality, not a plan. Our base case remains disciplined deleveraging while we continue to fund attractive growth and return capital projects and capital return to shareholders. That includes our dividend and the capacity for share repurchases. From a cash tax perspective, the Brazos Midland acquisition is expected to extend our runway by another year, deferring meaningful cash tax payments until 2032 from previously 2031.

I'll now turn it over to Randy for an operational and project update.

Thank you, Walt. Our teams continue to execute safely and reliably during the third quarter while advancing growth projects across the system. During the quarter, we completed our Denver area refined products pipeline expansion, adding 35,000 barrels per day of capacity. Demand has been encouraging, and we're beginning to evaluate further expansion opportunities. We also completed 110 million cubic feet per day of processing expansions in the Delaware Basin and are already seeing incremental volume with a continued ramp-up to capacity in early 2027.

In the fourth quarter, Medford Phase 1, Cutter 1 and Cassidy 1 are all expected to enter service, providing additional fractionation and processing capacity across the Mid-Continent, Powder River and Permian. Then in 2027, Bighorn adds 400 million cubic feet per day of processing capacity in the Delaware. Cassidy 2 adds another approximately 330 million cubic feet per day of capacity in the Midland and our Delaware NGL expansion adds 245,000 barrels per day of takeaway capacity. That expansion added this year supports growing Delaware volumes and connectivity with our West Texas NGL pipeline.

The acquisition of Brazos Midland assets also expands our opportunity set considerably. We're already advancing connections between Brazos and our legacy ONEOK system, which we expect will improve capital efficiency and commercial flexibility as we continue Midland Basin growth. Beyond what we've announced, we continue to see a growing set of opportunities across multiple products and regions, providing several pathways for continued organic growth.

With that, I'll turn the call over to Sheridan for a commercial update.

Thank you, Randy. Third quarter commercial activity was strong, driven by customer demand and volume growth across key portions of our system. Starting with the Natural Gas Liquids segment. Total raw feed throughput increased 6% year-over-year to nearly 1.7 million barrels per day. Our largest volume growth was in the Gulf Coast Permian region, where volumes increased 16% year-over-year and 9% compared with the second quarter, with nearly all of the increase from West Texas. Volumes continue to benefit from increasing producer activity, recently connected third-party plants and additional natural gas egress out of the basin.

Propane plus volumes increased both year-over-year and sequentially across all of our operating regions, driven by continued producer activity. Ethane recovery remained attractive across most of our system, supported by strong domestic and international petrochemical demand. We saw modestly higher rejection in the Rockies and Mid-Continent following strong recovery levels in the second quarter, while Permian economics continue to favor full recovery. Our fractionators are highly utilized as we work toward the completion of Medford Phase 1, which we expect in mid-December. Until then, we're continuing to build inventory of unfractionated NGLs, which defer the timing of the associated earnings from these NGLs. As Medford comes online, we will begin working through that inventory and recognize the associated earnings, primarily in the first quarter of 2027. We expect this to give us a built-in earnings benefit early next year.

Turning to the Refined Products and Crude segment. Refined Products volumes increased 6% year-over-year, including 10% growth in gasoline and 2% in distillates, supported by solid demand and high refining utilization across our footprint. Based on our year-to-date performance, we expect refined products volumes to finish the year near the top end of our original guidance range. Our connectivity and marketing capabilities also let us capture regional opportunities as wide Mid-Continent to Gulf Coast basis differentials and low inventories created price volatility. Midyear tariff adjustments added a further benefit.

Liquid blending also performed well. Increased gasoline throughput and the completion of synergy projects contributed to higher blending volumes during the quarter. We entered the fall season approximately 75% hedged and unhedged September spot margins provided additional upside. Historically, wide spreads have allowed us to lock in favorable blending margins throughout 2027 further out than we typically would. Export demand has also remained strong, with Refined Products volumes at Galena Park up approximately 15% year-over-year. Crude oil exports at Seabrook remain fully contracted with third quarter throughput approximately doubling the prior year period. In our higher-margin crude gathering business, we expect full year volumes to increase approximately 7%, supported by Midland producer activity averaging nearly 40 rigs on our dedicated acreage.

Moving to the Natural Gas Gathering and Processing segment. Volumes increased all 3 regions compared with the second quarter, led by record volumes in the Permian Basin. Volumes are higher across both the Midland and Delaware Basins in the Permian, led by growth in the Delaware following completions of our processing expansions. Across our dedicated Permian acreage, we have approximately 21 rigs, including 17 in the Midland Basin and 4 in the Delaware. The addition of the Brazos asset substantially expands our Midland opportunity with a long runway of high-quality drilling inventory and greater connectivity across the combined system. Importantly, what we've seen since announcing the transactions continue to support our acquisition assumptions.

Based on current producer plans, we expect an average of approximately 14 rigs on the Brazos Midland dedicated acreage during 2027. Producers are also encouraged by early Barnett results, including well performance and drilling and completion efficiencies, which are supporting increased development activity and a higher volume outlook. As we sit today, the current Brazos Sundance plants are full and volumes on the Brazos assets are above our expectations for this point in the year. We expect the continued volume ramp will be enough to fill Cassidy 1, which comes online at year-end. The larger combined system gives us flexibility to optimize the timing and location of that next expansion.

Outside the Permian, Rockies processing volumes increased 3% from the second quarter, and we're encouraged by activity in the area. Since March, Williston Basin rigs are up approximately 50% and rigs on our dedicated acreage have doubled to 16, approaching 2024 and early 2025 levels. The higher activity reinforces a stable, durable volume base and with our infrastructure already in place, incremental volumes translate directly into very attractive cash flow. In the Permian River Basin (sic) [ Powder River Basin ] , initial well performance around the Cutter plant have exceeded producer expectations, and we expect volume to ramp with planned completions in the fourth quarter and throughout 2027. In the Mid-Continent, growth continues across our Oklahoma system, driven by activity in both the Cherokee and STACK formations and several gathering expansions are underway to support further growth into 2027. There are currently 17 rigs on our dedicated acreage. Overall, producers remain disciplined, but current 2027 plans reflect increased activity and our conversations remain constructive.

I'll close with the Natural Gas Pipelines, where third quarter adjusted EBITDA was $231 million, up from $200 million a year ago, benefiting from higher optimization and marketing activity and higher firm transportation revenues. As expected, the Waha to Katy opportunity moderated sequentially as additional Permian egress entered service and price differentials narrowed. We expect a further reduction in the fourth quarter, which is already reflected in our guidance. Longer-term natural gas demand continues to provide significant opportunities.

Last quarter, we announced we had been awarded a supply agreement for 1 gigawatt of power plant demand. This project includes a 10-year firm transportation agreement for 250 million cubic feet per day of natural gas and is expected to be in service in late 2030. Additionally, we've been awarded another agreement to supply 110 million cubic feet per day for a 500-megawatt power plant expansion, which will go into effect in May 2028. These attractive return projects are good examples of the opportunities we are pursuing across our pipeline network, and we expect to announce additional projects as discussions advance.

Pierce, that concludes my remarks.

Thank you, Walt and Randy and Sheridan for that -- those updates. As I look back at the first 9 months of this year, the progress that we have made is significant. We've increased guidance 3x, significantly strengthened the balance sheet, expanded our position and scale in the Permian Basin, completed significant organic projects with additional projects approaching startup, and we're seeing constructive volume trends and producer activity across our footprint. Most importantly, though, those accomplishments, along with constructive producer plans and our hedging program, give us momentum and visibility as we enter 2027.

At the same time, the broader need for reliable U.S. energy infrastructure continues to grow. The energy landscape will remain dynamic. Our goal isn't to predict every geopolitical event or commodity price movement. It's to position ONEOK to perform through them. And we believe our scale, asset connectivity, financial flexibility and customer relationships give us the ability to do just that. We believe ONEOK will enter 2027 from a position of strength with a clear inventory of growth opportunities and the infrastructure required to help connect essential U.S. energy resources with the growing demand. And as always, none of this happens without our employees. I want to thank them for their continued commitment to safety, reliability, innovation and to serve customers.

Operator, we're now ready to take questions.

[Operator Instructions] And we'll now take our first question from Spiro Dounis with Citi.

I want to start off with new projects. Walt, you mentioned commercial teams working on some new opportunities here. Curious if you can expand and maybe give us a sense of what regions or commodities you're seeing the most activity and where that capital is likely to get allocated? And just to add on, Pierce, I noticed you added some commentary on the natural gas side. Sheridan seemed to support that with some of these data center projects. So curious if we can expect gas to maybe get a higher allocation than has historically been the case and if $3 billion plus is a good run rate to use from here on CapEx.

Yes. This is Sheridan. I would say as we start thinking about where we're going to see growth in CapEx and growth across our system is obviously we'll start in the Permian, where volumes are strong, growing strong. We already have quite a bit of processing capacity come online. We see the runway that we will be adding more processing capacity in the future. So that's going to create more opportunity for the NGL business as well. So we think we'll see a lot in the NGL in the Gathering and Processing segment in the Permian.

We're also seeing some opportunities in the Mid-Continent. We continue to see that grow. Volumes are up strong. We could have some allocation of capital into the Mid-Continent area. As you start thinking about refined products, we've seen a big pull of volume -- export volume that's changing the dynamics on our system. We could see some optimization opportunities or being able to increase our capacity between the Gulf Coast and the Mid-Continent be an opportunity. We're also looking to expand the Denver pipeline that came up this year, completely fully contracted. Commercial teams are working with other people to see about the opportunity to expand that system as we continue to go forward.

And then obviously, the data centers. We continue to be in discussions with a large number of data centers. A lot of them continue to advance. Last quarter, we announced one. This quarter, we're announcing another one. The teams are on the edge on a couple of other really nice projects as well. So we will see some area from power demand going forward on the natural gas pipe. So really, when we think about capital and the capital we're looking about across our footprint, it's in all the segments as we go forward. It's not really concentrated in one area or the other.

Spiro, this is Pierce. The only thing I'd add to that is much of the gas that we move is going to be feeding LNG facilities as well as the electric generation, either for utilities or for AI data centers. It comes with liquids. And so the gas demand that we see also will increase the gathering and the processing opportunities that we have along with moving the liquids associated with those gathering and processing plants and the fractionation facilities, and it gives us more blending opportunities with those products into our RPC business. So it touches all phases of our business.

Got it. That's helpful color. Second question, moving to NGL volumes, tracking to be above the high end of your guidance this year, but you did see some volumes come in quarter-over-quarter in the Rockies and Mid-Con, Sheridan, and I suspect that was really a function of ethane rejection, but maybe would appreciate more color there and how you're seeing the rest of the year shape up. And if you could maybe just talk through what changes when Medford comes online? Is there an easy way to sort of quantify the impact of storing all these NGLs and how quickly you'd expect Medford to fill up?

Yes. I think -- Spiro, you're exactly right. The little bit of fall off we saw in the Rocky Mountains and Mid-Continent where the NGLs was all ethane. As I said in my remarks, the C3+ volume is actually up. So that the underlying growth is strong there. There's a little bit more ethane rejection. Some of that is on our own cost coming out of the Bakken that we dialed back our incentivized ethane a little bit just due to the market conditions we're seeing right now.

As we continue to move forward on NGLs, we continue to see growth. And a lot of that growth is going to come out of the Permian is where we'll see a significant amount of that growth going forward as we continue to ramp up our natural gas gathering and processing assets out there in the area. So we see going forward.

Now when Medford comes up, the impact of Medford is because we do have raw feed that is in storage today, obviously, we have more raw feed coming to our system than our current fractionators can handle. Medford will come up completely full for a period of time as we work off that raw feed and inventory. So both Phase 1 and Phase 2 will be full for a period of time going forward. But then we'll be able to leverage that into growth after that's worked down that growth coming out of the Permian that we see as we bring on the Brazos plants continue to fill our legacy ONEOK plants out there going forward.

As Randy said, we've already -- we are in the process of tying Brazos and the legacy ONEOK Midland systems together, which we will be able to remove volume that we're doing on third parties today. We have offloads in our G&P Midland system today, third parties, we'll be able to bring that into our own plants and create more NGLs, which will be able to fractionate through Medford going forward.

When we put Medford -- when we actually came out with Medford, we had said that we had not subscribed 100% of that capacity because it was a lower cost fractionator. If it was a brownfield fractionator, we didn't need to subscribe all of the capacity. So that we had additional operating leverage that we could continue to contract. The commercial team has continued to contract as we've gone through this build phase. We still have capacity that is uncontracted today, but that is a lot less than we had before. And we think that gives us a lot of leverage to be able to contract even more third-party volumes as we have done with our Delaware expansion.

We'll now take our next question from Jeremy Tonet with JPMorgan.

Just want to touch on the guide for '26, if I could a bit. And if we're looking at it right, it seems like it implies 4Q doesn't really move up versus 3Q in any meaningful fashion. And that would even be with the Brazos contribution. So just wondering if you could talk a bit more gives and takes in the fourth quarter, think of it as maybe seasonally a bit stronger as well. Is that conservatism? Or are there other elements at play here?

Jeremy, this is Walt. As I said in our remarks, we have remained cautious throughout the year, just given the whole geopolitical situation. If everything stays like we are today, we are probably on the conservative side, and you could expect a nice tailwind that will be in the fourth quarter and with the rig activity that we're seeing now really continue into 2027 pretty strong.

Got it. And then maybe just moving over towards the fractionation side, picking up a bit more on the comments you said. It seems like Medford would bring a lot of optimization opportunities or flexibility to the system. But then even if I look at the NGL raw supply that you guys have versus fractionation capacity, it still seems maybe the system is a little bit short and could need some more fractionation build-out, particularly when you're thinking about all the processing plant additions and the dock and export coming up here. Just wondering how you think about that growth opportunity.

Yes, remind -- yes, we watch that very closely, Jeremy, to understand where it is. Now remember, not all the volume you see that we report, we fractionate, some of that we just transport on that. But what I would say we do have a little bit extra capacity in Medford, and we do have MB-7 that's already permitted. And then we're just trying to understand when the right time is that we FID that to be able to make sure we have fractionation capacity for our growing gas processing plants.

Our next question will come from Manav Gupta with UBS.

I actually just wanted to go back to Brazos and ask you about now that you have had some look at these assets, are they actually meeting your expectations? Where are the areas where you think actually there could be some upside here? If you could give us an update on how you're thinking about the synergies now that you have had some chance to look at these assets at a closer look? That's my first question.

Yes. What I would say is that we are very, very satisfied with what we've seen with Brazos. I mean, as I mentioned in my remarks, that volumes are above our expectations at this time of the year, at this time in the process, and we -- nothing tells us that they're not going to continue to be above our expectations as we move into 2027.

The assets in general, we have found them -- we've been very pleased with the assets in general. They put some very big pipelines in their area. They didn't just build enough what they had. They do a lot of things like we did. They upsized their pipelines, and that's given us a lot of capital synergies immediately. We actually were going to have to expand one of our main lines on our system on our legacy ONEOK gathering and processing system. But because Brazos overbuilt this system, we're immediately able to access that capacity and save that capital.

And that continues to happen going forward as we look at it. As we get these plants up, we're very pleased at how well they built the plant, the redundancy they put in there. They built them like we would. They built them to last. As we continue, as I talked about on the volumes, we continue to talk to producers, producers get more and more excited about the Barnett and what it means, the efficiencies and as they get better at it, the volumes exceeding their expectations per well. So right now, Brazos is probably hitting on all cylinders of what we expected to. We're very pleased with what we've seen so far.

And this is Pierce. I can't emphasize enough Sheridan's last comments about the quality of the way these assets have been built. Randy and I both background is in the construction of these kind of things. And I can walk around that plant and tell that they've addressed a lot of the things that I've seen as problems in the past with other companies and other assets. And I think they built them for reliability and resiliency. So I'm very, very pleased with the quality of the assets that we picked up.

Perfect. My very quick follow-up here is we noticed in the slide deck, the Delaware NGL expansion of 245,000. And we also know you have the processing plant at Bighorn coming around like 400,000 (sic) [ 400 million ] somewhere in 2Q, and this new expansion is 3Q. So can you talk a little bit about are these 2 projects in some form complementary to each other?

They are a little bit, but really this expansion that we're doing, we're really laying a pipeline from our Texas Delaware up to the Northern Delaware and New Mexico. So we're opening a new area. We did upsize this expansion more than we needed like we've done in other lands. We have a lot of growth there. It's backed by third-party processors and producers that have contracted for this space. And with that extra capacity, we really are excited about being able to access a different part of the Delaware Basin, that Northern New Mexico Delaware, where there's a lot of opportunity for us to compete for third-party processing plants in that third-party NGL volume.

We'll now take our next question from Jean Ann Salisbury with Bank of America.

Bakken rigs have gone up markedly in the last month or 2. Have you heard from producers that they're adding activity in the Bakken at these oil prices?

Yes, we have. They are. Obviously, they're adding activity. We have more rigs coming online. And what's interesting about that is we're seeing more rigs come in or rigs come back from producers that are multi-basin producers that have other opportunities across the whole North America, and they are bringing rigs back. So we are very -- we're excited about what we're seeing. And in some of these areas, they're drilling in the core of the core, which is great, great for us, and that volume is all coming to us as well. So yes, we are seeing more activity in the Bakken with this rig count and from a different type of producer that we haven't seen before, which is very encouraging.

And there's obviously been a lot of Permian M&A in recent months, specifically of G&P M&A. What do you attribute this uptick in activity to? A lot of these G&Ps had kind of been out there for a long time? And then I guess, relatedly, what are the key criteria when ONEOK assesses these for fit within your portfolio? Is the ability to direct NGLs a must-have component when you're screening these things?

Jean, this is Walt. Yes. I think that you asked why there are so many of these transactions. Clearly, with commodity prices where they are, the private equity backers are looking at this as a window and opportunity to sell when the market is as strong as it has been. So they're all testing the market. Many of these assets have tested the market before. But at these levels, you're seeing some activity.

And the other thing is that there are fewer and fewer of those opportunities out there. So as people look at trying to round out, they've decided to act. And many of them have derisked quite a bit. In previous years when they've tried to come to market, they had a lot of space, but maybe not a lot of volume. Many of them have been able to do a good job filling those up. So it -- I think it's just the maturity of the basin with the backdrop of a great commodity price that's bringing people to the market.

And I guess what are the key criteria for ONEOK when you're screening them?

I mean, the NGLs -- I apologize, I forgot that part of the question. NGLs is clearly something that would be important to us and something that we look at. It's one piece to the overall picture. But to the extent that we can use our integrated system and continue to touch that molecule throughout the chain, that is what our strategy is. So if we can capture those NGLs, that definitely would screen better on our radar for sure.

Walt mentioned that this was a part of the criteria. But the areas of dedication, the locations of those areas of dedication in and around the existing assets, both from a legacy standpoint and the new assets that you'd pick up, the quality of the producer that's drilling those areas. There's a multitude of things that we look at all to basically derisk what it is that we're looking at and where we spend our capital.

We'll now take a question from John Mackay with Goldman Sachs.

You touched on this a couple of times, I think, in the context of the incremental balance sheet capacity. But just as you guys are out there looking to add new organic growth projects, could you touch a little bit about where you think kind of run rate annual growth CapEx could get to? And maybe any sort of range you want to put around that, keeping the leverage target in mind?

Sure. Well, as we've said, '27 will look somewhat like '26. We expect a lower level than '26, but we still have some reasonably big projects finishing up with Medford wrapping up in 2027, process -- large processing plant, several plants actually and then the dock. So you should think around that $3 billion-ish, give or take, for '27. And then we would expect it to range between that $2.5 billion to $3 billion going forward, which will still leave us with quite a bit of free cash flow to return capital to shareholders.

I appreciate that. And just second one for me. On the Northern Delaware NGL expansion, anything you can comment in terms of mix of third-party counterparties there, either producers or is it all midstream? And then is that a -- would you expect that to be kind of like full chain margin, including frac all the way to Belvieu from the Northern Delaware? Or is it just a portion?

Yes. So the first thing, it is both. We have multiple third-party processors that have signed up for this capacity and producers on that. So it's a very nice mix between there. The -- it will be almost entirely is a full value chain transportation and fractionation. There is a little bit that will be just transport only, but it is highly all transportation down to Mont Belvieu and fractionation into Mont Belvieu. And we think that ramping will be -- what we -- the volume that has underwrote this will be coming up fairly quickly once it's put into service, and that will be into the third quarter of '27 when it comes up in service.

We'll now take our next question from Theresa Chen with Barclays.

Walt, would you further elucidate the shift in your leverage philosophy operating with lower leverage on a run rate basis? Is this rating agency led? Is it that you're seeing more commodity volatility across your base business versus previously? Or is it more driven towards shoring up dry powder in the event of attractive inorganic opportunities complementing your organic ones?

I would say that it's no one particular thing. As we've gone through these transactions and lived through commodity cycles, we think maintaining the flexibility to look at opportunities and not stress the balance sheet is important. We have seen a lot of interest from large shareholders in seeing a lower leverage in the business. Yes. So we're in the view that we did not do it just to get a BBB+, that's for sure. But we're very pleased that the rating agencies have recognized that we intend to operate the business with a lower level of leverage. So it's a little bit more conservative. We've seen some pretty significant commodity cycles over the last 10 years, and there will be another one at some point.

And as you evaluate further expansion of your Denver pipeline, how could the next phase differ from the initial project now that that's online, both in terms of scale and product capabilities? Would it be fair to assume that the next phase would handle products beyond jet fuel? What would you need to see to move forward towards an FID? And what are you seeing in terms of demand in that market as well?

Yes. I mean, really, we set this up very nicely that the next expansion of Denver is not going to be a huge capital expansion. And so really, what we're looking for is talking to the customers of them wanting to sign up for that capacity. And they're looking at not only what's going on in the Front Range, but overall, what's going on in PADD 4, what they're looking at and how they continue to move that out or other inter movements within PADD or how that would affect the Front Range.

So really, to FID that project, we just need to get to the customers and have them ready to sign up for the space is really where we're at. And we're having those conversations today. But obviously, that plant -- that pipeline just came online. We're moving more volume. People want to see how the market is reacting to this additional volume. We are seeing increased jet fuel demand across our whole system, and Denver is no exception. But obviously, this new capacity is meeting that demand today.

But I will say we are having quite a few conversations with customers about the next expansion of Denver. And we -- the thing that is unique about it is if they come in and want a little bit, we can give it or they want a lot. We can scale our expansion to what the customers want to sign up for. That's the beauty of us putting this operating leverage in the pipeline we laid for the first time.

We'll now take our next question from Praneeth Satish with Wells Fargo.

Just on Brazos, I was wondering if you could help bridge the -- so in Q4, looking at the contribution, I think if you annualize it, it's about $350 million of EBITDA. The 2027 target that you provided when you made the acquisition was $590 million. I know you have Cassidy 1 and 2, so that's probably part of it. But maybe like what are the other key drivers? And then how much visibility is there into filling up those 2 plants and getting to that $590 million target for '27?

Well, this is Sheridan. What I would say is, obviously, Cassidy 1, as I said, is coming up here at the end of this year. It will fill relatively quickly on that. So you're going to get another 330 million a day of processing capacity we're processing. Right now, we have 550 million. So we're increasing by over 50%. Then also as we tie that system into our system, we'll be able to access our processing capacity as well. And then you get the downstream effect of the NGLs that are coming off this increased processing capacity to us as well.

So it's kind of a twofold that we're getting continue to go forward. So -- and then Cassidy 2, when it comes up, we will have to have used our legacy system when Cassidy 2 comes up. So everything is pointing to that Cassidy 2 will ramp up fairly quickly. As I said in my remarks that we are actually ahead -- volume is ahead of where we thought we would be at this time and projections are showing that, that's going to continue well into 2027, especially with our conversations with the producers out there that are getting excited about this Barnett and what they're seeing. They're seeing better results than they had anticipated from a volume standpoint on the gas. So we think it will -- that's how we're going to get to that higher number.

And Praneeth, this is Walt. I think the important part today is that the 550 million that is there is full, and we're doing offloads at this point. So if we had the capacity, we would be at a higher number. But until we bring in that Cassidy 1 plant, we will take a stair step up as we go into 2027.

Got it. That's helpful. And maybe just staying on Brazos. So Sheridan, I think you noted that you expect 14 rigs on the Brazos acreage in 2027. I guess with commodity prices moving higher and some of these results here that the producers are seeing from the Barnett, like is there any interest from producers on the Brazos system to add rigs? Do you think there's a possibility that, that rig count moves above 14 rigs in 2027 based on the discussions you're having with your customers?

Yes. I do think there's an opportunity for it to move up. We do have some customers that are continuing to look at that, continue to see where they want to deploy those rigs. As they get more and more comfortable with the Barnett, what's going on, they're probably going to be moving more into that area. So yes, we think it could definitely move up. We're just seeing our discussions right now as they're saying this is where it is. But right now, they know they're going to have this many rigs on there and there could be more coming. We just need to see how we get into -- a little bit more into '27.

Our next question will come from Brandon Bringham with -- I'm sorry, Brandon Bingham with Scotiabank.

I wanted to maybe get a little more clarity around the crude volumes during the quarter, looked a little bit light. Just what can you say about some of the dynamics around the crude piece? And then maybe how should we think about the forward trajectory of Permian crude, especially in light of all of the gas that is forecasted to come online through the end of the decade?

So -- this is Sheridan. What I would tell you is, is that the crude number we give you is a total system number. That includes both the gathering volumes, volumes that travel down our long-haul pipelines and also volumes that we move through our Houston distribution system. Each one of those have very different rates on there. And Houston distribution system, which is where a lot of the volume moves is at the lowest rate. That's why in our remarks, we talked about the high-margin volumes are our gathering system out there in the Permian, and that is up 7%. And that's why we're trying to give you that number because we know there's other pieces and parts that move around in there because we've only given you one number.

And there's another effect of how we kind of account for numbers depending on where they go and what systems they go through, how many times they get counted. So overall, we are -- we like where our volumes are. They're growing. They're growing where they need to grow. That means they're growing in the gathering system. We continue to see that grow as we have 40 rigs on our acreage right now drilling. We continue to expand our acreage dedication that we're getting from people and continue to grow that volumes, continue to make connectivity between our systems, continue to make connectivity between our gathering systems and our long-haul pipelines.

Our long-haul pipelines are predominantly full right now at this time. They're moving at rates. So I know it's a little bit hard because we show a little bit of drop in volumes. That is around our Houston distribution system, where that is, which is by far the lowest margin, but our gathering volumes are up nicely at 7%.

And Brandon, if you're going to continue to see the LNG growth in the Gulf Coast there, another 12 Bcf a day, it's our belief that a lot of that gas is going to come out of the Permian Basin. So there's 2 things that's got to move there, either the volume of crude has to go up, therefore, lifting the gas or the GOR has to go up if the volume of crude stays flat. Our opinion is they probably both will move up. So there's going to be more crude, I think, to move out there in the future.

I agree. Very helpful. And then maybe one quick follow-up. I know you said you were going to wait for 4Q to kind of get into specifics, but is there anything maybe more qualitative or high level you could discuss maybe for the non-Brazos piece of the business as Brazos feels kind of pretty well understood at this point?

I think you're getting on what's the guidance for '27. I do want to reemphasize that we're not going to give guidance today for 2027. But I can tell you from where I sit, I really like where 2027 is setting up for us.

I do think it's important -- to add to that is you really have to -- see, we've talked a lot about the Permian today and probably haven't given the Mid-Continent its due because the Mid-Continent activity has picked up significantly. And we're not only seeing it on the western side of the state, we're now starting to see the STACK come back a little bit, too. So we're excited about the Mid-Continent. The Powder has been doing great. So across each of the basins, we've talked about the rigs in the Bakken. So we're seeing that across all the basins.

Our next question will come from Julien Dumoulin-Smith with Jefferies.

You've actually got Patrick this morning. On the first one, I was wondering if you could add a bit more color around the hedging. I know you said you don't want to do '27 guidance, but how does this fit into your high -- mid- to high single digits long-term growth trajectory? I mean, if you -- I think you said 75% hedged into 2027 at these prices. Can you just add some color about how that relates to your longer-term earnings guidance, if you expect that to be kind of sustained or if that would drop off pretty sharply, assuming geopolitical normalization?

Yes. This is Sheridan. First thing is, yes, we did not say we're 75% through 2027. We were 75% coming into the fourth quarter of into the third quarter of 2026, and that other 25% gave us quite a bit of uplift. But as we talked about as hedging going into 2027, with these wide margins, we are seeing an opportunity to hedge more than we typically do. We have a very programmatic hedging that we are on a cadence when we hedge. We're not really trying to call the market. But when we see times like this, we do have the ability to accelerate that hedging.

And we've done that into 2027, more so in the first part of the year because of the backwardation in the market. And obviously, that backwardation is a sign of strength. So we really think the market will kind of come up as we get out in '27. But we are more hedged now than we typically are at this time of the year at these wide margins. Obviously, that has just come of late. And when I really think about this medium to high single-digit growth rate. That's really going off the base business and more of what we typically see in our margins going forward. So commodity price could be a nice little tailwind.

Okay. And I think a second bit, maybe a minor question was, do you tell us how much inventory is building for NGLs that Medford would need to process?

Could you say that again?

Do you tell us how much inventory is building up for Medford to process?

It is -- sorry, I apologize. We haven't come out and said exactly how much inventory we have, but we have quite a bit of inventory right now that we've been building since the second quarter, anticipating of Medford coming on as we've been successful in being able to contract more volume and growth across our system. So Medford is going to run full for definitely the first quarter and probably into the part of the second quarter when it comes up.

And that will earn the product prices at that point in time where you've hedged the prices that it will get as it processes all that inventory back?

So there's 2 things that happened is because of the way of accounting, we could not -- we cannot account for our fee-based earnings that we received from those -- that volume that we put into the well. So when we fractionate that volume, we will get the fee-based earnings associated with those volumes in the well. Our marketing team has already hedged those out into the future to take out the commodity price on it. So the earnings you'll see next year coming from this will be from the fee-based portion that is we cannot record until we fractionate the barrel.

We'll now take a question from Keith Stanley with Wolfe Research.

I wanted to follow up on the Delaware NGL expansion pipe. Should we think of the 245,000 barrels a day as mostly spoken for with new long-term contracts? Or is this creating a lot of white space for you in New Mexico? And then related to that, any update on how full you are now on the -- I think it's 750,000 barrels a day of West Texas LPG capacity all the way to the Gulf Coast?

Yes. So on the Delaware expansion, we did -- we think it's a very strategic pipeline. We think it goes to an area that there's a lot of opportunity to pick up third-party NGL volume. And so we did go in there and upsize that pipeline for that. So there is quite a bit of white space that we have there to be able to leverage and to be able to increase the volume on that system. And then overall, we still have around a little over between 200,000 and 300,000 barrels a day of space on the West Texas NGL pipeline going forward. Obviously, with our expectation with Brazos, Brazos is going to fill up quite a bit of that. And then our growth across our other base business will help us give a substantial amount of that pool.

Great. Quick one second question on the refined products optimization. So you were up Q-over-Q in the third quarter on higher blending results. The slides often talk about Q2 and Q4 as the big blending quarters. Should we assume some of the blending sales were pulled forward from Q4 into Q3? Or is there anything else you'd point to on Q3 being very strong?

Yes. Q2 was strong. Obviously, we had some very wide margins in there that made it really good. Volumes were good, which was kind of a culmination of a lot of our synergy projects that we've been being able to put into place. We've actually -- we talked about this. Magellan, when we bought it, they were spending around about $0.20 per gallon for their normal butane to get to the right place and to be able to blend because they are moving a good portion on trucks. The synergy projects that we've been able to put together have moved almost all that on to pipeline, and we've been able to cut $0.10 a gallon out of that. So what we're blending now, even though we had wide margins and then we had lower logistics cost to get there. And those logistic costs will be there every year. I mean, that's permanent, continue to go forward.

So that -- and then a little -- we had some -- there was a little bit of waiver help. In September, they moved from the first -- September 15 to the first of [ 15 ] that you can -- the RVP change that gave us some more volume to be able to blend into. And frankly, we're just getting better and better at it. And you're right, the other thing was good is we are seeing increased gasoline volume across our system. The more gasoline volume across our systems, the more opportunity we have to blend.

So there's 3 or 4 things that have really contributed to that. And as we go into the fourth quarter, we're still seeing good margins. Obviously, logistic costs are still there and volumes across our system are strong compared to where they are historically.

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

Thanks, Anna. Our quiet period for the fourth period begins when we close our books early next year and extends until we release earnings in late February. Our IR team is 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 call on the recently announced Brazos Midland acquisition and Minority Equity Investment. As a reminder, this call is being recorded. Today's call will be 30 minutes. [Operator Instructions]

At this time, I would like to turn the conference over to Megan Patterson, Vice President, Investor Relations.

Megan, please go ahead.

Yes. Thank you, Taren. Good morning, everyone, and thank you for joining today's 30-minute call. Along with last night's announcement, we provided a presentation deck with additional information that is 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. On our call is Walt Hulse, the Chief Financial Officer; Randy Lentz, Chief Operating Officer; and Sheridan Swords, Chief Commercial Officer, are also available to take questions.

Yesterday, we announced two transactions that significantly strengthened ONEOK. These announcements included a definitive agreement to acquire Brazos Midstream's Permian Midland Basin natural gas gathering and processing assets for $4.425 billion and a $9 billion Minority Equity Investment from Apollo that will fund the acquisition and be used to extinguish approximately $5 billion of debt, lowering our debt-to-EBITDA to 3.25x.

Our strategic rationale is straightforward: acquire a premium complementary Permian Midland Basin growth platform, growth that feeds and fills ONEOK's contiguously integrated system, accelerate earnings and free cash flow per share and strengthen the balance sheet without issuing common equity. These transactions begin creating value day 1. The acquisition is expected to be immediately accretive to earnings and free cash flow per share. It also increases momentum for the high end of our mid- to high single-digit adjusted EBITDA growth target over the next 5 to 7 years.

The approximately 7.5x 2027 EBITDA acquisition multiple includes approximately $80 million of full year synergies by 2028, expected significant Brazos growth and additional integration benefits reduce the multiple to approximately 6x. This is a decisive step in the strategy that we have executed for years, building scale in the most attractive producing regions and connecting that supply to ONEOK's integrated system to drive long-term shareholder value. The Brazos assets provide an additional high-quality position in the core of the Permian Midland Basin, supported by approximately 600,000 dedicated acreage, leading producers, 14 active drilling rigs and long-term fixed fee contracts with weighted average remaining term of more than 12 years. This is contracted growth that creates exceptional visibility.

Following completion of the Cassidy II plant expected in the third quarter of 2027, Brazos will have approximately 1.2 billion cubic feet per day of processing capacity and 700 miles of gathering infrastructure. These high-growth assets give ONEOK immediate scale, elevating our gathering and processing capacity position to the third largest in the Midland Basin and provide a long runway of identified expansion opportunities in one of North America's most economic and attractive resource plays. The combination of quality, visibility and growth is difficult to replicate.

It's also important to recognize that Brazos builds on a position of strength. ONEOK already operates nearly 1.8 billion cubic feet per day of natural gas processing capacity in the Permian Basin with more than 1 billion cubic feet per day of processing capacity and approximately 1,200 miles of gathering infrastructure across the Midland Basin specifically. Earlier this year, we relocated the 150 million cubic feet a day Shadowfax plant into the Midland, further demonstrating our confidence in the basin's long-term growth outlook. ONEOK is uniquely positioned to maximize the value of these assets through our fully integrated value chain.

We operate an extensive energy infrastructure system that spans from the Canadian border to the Gulf Coast, connecting gathering, processing, transportation, fractionation, storage and export capabilities across multiple commodities. Brazos volumes connect directly into that system. Natural gas and NGL production gathered and processed in the Midland can move through our West Texas NGL pipeline into our fractionation assets and ultimately to our Gulf Coast export facility as it comes online. We're not acquiring a stand-alone earnings stream. We are securing high-growth supply that can drive utilization and value creation across infrastructure throughout our system for years to come.

Together, ONEOK and Brazos create one of the Midland Basin's largest integrated natural gas gathering and processing systems with the transaction more than doubling our Midland Basin processing capacity to approximately 2.3 billion cubic feet per day, including plants under construction. The combined footprint gives us greater commercial reach, operating flexibility and future development opportunities. We can optimize capacity across systems, connect more volumes to downstream infrastructure already in place and deploy capital more efficiently across a larger platform. And to support the next phase of producer growth, we have secured 2 additional processing plants that we can locate as needed once a final investment decision has been reached.

This is another example of our disciplined and intentional approach to M&A, and we are equally deliberate in how we finance the transactions. We had two clear objectives: fund the acquisition without issuing common equity and diluting shareholders, continue accelerating our deleveraging trajectory and maintain our financial flexibility. Minority equity investment from Apollo accomplishes both. It funds the acquisition, supports our balance sheet objectives and preserves future value creation above Apollo's capped return on ONEOK's common equity shareholders.

Just as importantly, it also allows us to acquire a premier Midland Basin Permian platform while improving leverage to approximately 3.25x, well below our previously stated long-term target. That stronger balance sheet positions ONEOK to fund our organic growth project backlog and accelerates flexibility for increasing capital returns over time, including potential dividend increases and share buybacks.

I'll now turn the call over to Walt to discuss the financial aspects of the transactions in more detail.

Walt?

Thank you, Pierce. Let's start with an overview of the financing transaction. Funds and affiliates managed by Apollo will invest $9 billion in exchange for a nonvoting Class B interest in a newly formed holding company that will sit below ONEOK and owns the operating company that holds all of ONEOK's assets. ONEOK will retain the Class A interest and all of the existing indebtedness will remain with the assets at the operating company. Many companies in the midstream space and other industries broadly have used variations of this insurance capital structure. However, to date, those capital raises have been done at the asset level.

Our financing is the first to utilize this type of financing vehicle to raise nondilutive equity capital at the corporate level. The major difference between our transactions -- transaction and the ones done previously by other companies is that the previous deals were done with a first call on the cash flow of an asset and as such, are structurally senior to all existing company debt. Our transaction is the exact opposite. We have created another funding entity above the operating entity, so all of our senior notes and other debt remains at the entity with the operating assets. The equity financing we did is structurally subordinate to all of our other existing debt.

By paying down debt at the operating entity and funding that debt repayment by raising equity capital one level up at a holding entity, we have materially improved the credit profile of our operating entity where all existing senior notes and other indebtedness remains. The Class B interest is expected to receive quarterly distributions equal to 15% of cash flow from operations and its return is capped at a 7% internal rate of return for the first 9 years of the investment. The cap is critical. The investors in the Class B units do not participate in Brazos growth, ONEOK's existing growth portfolio or future value creation. All value creation above the capped return belongs to ONEOK's existing common equity shareholders.

The structure we utilize is also self-amortizing. Cash distributions above the amount required to earn the capped return reduce the Class B capital account balance. As that balance declines, more of ONEOK's economic value accrues to common shareholders. Economically, this functions much like a built-in share repurchase program. Every dollar distributed above the capped return permanently retires a portion of the outside capital account at a price we already know and that value accrues to every common shareholder. The difference is that it requires no market timing, no incremental cash beyond what the business is already generating and it happens automatically throughout the life of the investment.

We can accelerate the Class B capital reduction by electing to increase the Class B distribution for any quarter from 15% to as much as 20% of cash flow from operations. Beginning on the eighth anniversary of closing or sooner if the Class B capital account reaches a balance of $200 million, ONEOK has the unilateral option to acquire the remaining Class B interest. We expect the Class B capital balance to have declined substantially by the eighth anniversary of closing. The Class B interest is nonvoting, has no Board representation, has no liquidation preference and is structurally subordinate to all ONEOK senior debt.

Importantly, we reviewed the structure in advance with all 3 credit rating agencies, each of which view the transaction as credit enhancing. Early this morning, Fitch placed ONEOK's ratings on credit weight watch positive and stated that Fitch will resolve the rating watch positive with a 1-notch upgrade to BBB+ upon closing of the minority investment and debt paydown. We expect these both to be complete by September 20. Fitch also stated that they treat the minority investment as equity. Under GAAP, the capital we raised is recorded as permanent equity as a noncontrolling interest.

To reiterate what Pierce mentioned earlier, we evaluated a full range of financing alternatives. Incremental debt would not have advanced our deleveraging and issuing common would have created permanent dilution and transferred a portion of our future growth to new shareholders. The minority equity investment is the only structure that funds the acquisition, accelerates deleveraging and avoids common equity [ insurance ] and preserves the upside we are creating for existing ONEOK shareholders. In addition, to fund the acquisition, the proceeds from the minority equity investment will be used to extinguish $5 billion of debt through repayments, a tender offer and make-whole calls.

Concurrent with the announcement of these transactions, we also announced in a separate release a tender offer for certain tranches of our senior notes. Because a number of the notes included in the tender currently trade well below par, the face amount of debt we retire will potentially exceed the cash we deploy by approximately $300 million. We expect to record a modest gain on extinguishment. That gain is a onetime item, and it is excluded from the accretion figures we have discussed this morning. These actions immediately reduce our leverage below our previously stated 3.5x debt-to-EBITDA target. We expect our pro forma 2027 debt-to-EBITDA ratio to be approximately 3.25x.

Going forward, we intend to maintain leverage around 3.25x debt-to-EBITDA or even lower over time. This lower leverage philosophy will give us the financial flexibility through business and commodity cycles and as organic and inorganic opportunities present themselves without stressing our balance sheet or reducing our flexibility to return capital to shareholders as appropriate. In one step, we are funding a highly accretive acquisition, exceeding our deleveraging objective, avoiding common equity issuance and retaining the upside from the growth we are creating. No other financing alternative could achieve this full set of outcomes.

From an accounting perspective, the investment will be recorded on the balance sheet in permanent equity as a noncontrolling interest. On the income statement, approximately 7% of the investment remaining capital balance will be subtracted from net income to arrive at net income attributable to ONEOK. As quarterly distributions reduce the capital balance, the average balance across 2027 is expected to be meaningfully below $9 billion, and the charges step down every year after -- as the balance amortizes. That declining charge is a source of earnings per share growth that is independent of EBITDA growth due to the built-in return of capital.

Free cash flow per share will reflect cash available to ONEOK common shareholders after the Class B interest and after common dividends have been paid. We note that this is a more conservative definition of free cash flow per share measure commonly used across our sector and it's the basis for the accretion we've referenced earlier. At this time, we're maintaining our recently increased full 2026 financial guidance, and we'll provide an additional update along with the third quarter earnings in October. Looking ahead, the minority equity investment is expected to close in the first half of September and the Brazos Midland acquisition is expected to close in the fourth quarter of 2026, subject to customary regulatory approvals and closing conditions.

Pierce, I'll turn it back to you.

Thank you, Walt.

The Brazos transaction strengthens our Permian position, expands our integrated system, accelerates earnings and free cash flow per share growth and enhances our long-term growth outlook. We look forward to welcoming the Brazos employees that will be joining us upon close. The minority equity investment by Apollo also allows us to achieve those objectives while accelerating deleveraging, avoiding common equity dilution and preserving the future upside for our shareholders.

I want to thank the teams that worked on this acquisition for making it possible. And as always, I want to thank our more than 6,000 employees for what they do every day to move energy critical to our economy, national security and the quality of our life.

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

[Operator Instructions] We'll take our first question from Gabe Daoud with Truist.

Congrats on executing this transaction. I was curious if we can maybe start with Brazos and maybe give a little bit more color around current volumes on the system, what's kind of underpinning the significant EBITDA growth in '27 and '28 from current levels? And it does appear EBITDA expectations off the capacity is a bit rich. So just kind of curious what's driving the assumptions around the Brazos ramp?

Yes. Gabe, this is Sheridan. What I would say from on the NGL side, we're receiving about 30,000 barrels a day from Brazos, and we expect that volume to reach an additional 120,000 barrels a day or up to 150,000 barrels a day by 2029. So the volume on the system support that. And today, we are getting all the NGLs from that system.

I think the -- what's supporting that growth is you've got fantastic producers with about 14 rigs currently running on the acreage. Just recently having added a major producer with a [ PDP ] that came on. As the plants come up here, they will fill very quickly. In fact, there are already offloads going on because the plants are -- the production is ahead of the construction. So we see this filling very quickly and a growth profile that could grow about 20% a year from 2027 through for the next 4 years or so.

Okay. Great. That's helpful. And then I guess just a quick follow-up around the structure, pretty interesting piece of paper. But curious if you can maybe again compare and contrast some of the options that you have here and maybe with the increase in balance sheet capacity, how that gives you some flexibility for return of capital or maybe even more M&A down the line? And again, just kind of curious with the 7% piece of paper, taking out 5% cost of debt, maybe why you view that as making sense at this point?

We think that operating with leverage at 3.25x or lower gives us an enormous amount of flexibility to take advantage of organic and inorganic growth opportunities without stressing the balance sheet. And at the same time, as many of you have modeled, as we move forward here, we're producing an enormous amount of free cash flow that will allow us to return capital to our shareholders while we're pursuing these growth opportunities and getting ourselves to the 3.25x quicker allows us the flexibility to do all of that sooner. So we just think that at this point in time and moving forward, having financial flexibility and keeping leverage lower is the right strategy.

[Operator Instructions] We'll take our next question from Theresa Chen with Barclays.

Pierce, I wanted to go back to your earlier comment about the momentum to get to the high end of your mid- to high single-digit EBITDA growth target over the next 5 to 7 years. With the pro forma platform, how is ONEOK better equipped to win market share and/or grow in the Permian? Can you provide more details on the runway of the identified expansion opportunities you alluded to? Are they organic, inorganic? Any thoughts there?

I think it's 3 things, Theresa. Number 1 is scale. This acquisition significantly increases our scale to a very competitive position in the Midland Basin. That's number 1. Number 2, there's over 600,000 acres that's dedicated under this particular contract for long-term contracts, 12 years. And number 3, it has an AMI associated with it that as the producers that are there expand into other areas, then those expansions then get basically offered to us.

So it's the combination of those 3 things and the fact that when they overlay our existing assets, we're able to spend less capital, move more volume. And I really like the way Brazos has built in additional capacity with a lot of these pipelines out there that's going to really, really contribute to us moving way more volume out there than we could have in the past. I'd end by saying that these 2 companies can move more volume with less capital than they could apart.

Our next question comes from Praneeth Satish with Wells Fargo.

Just on the acquisition economics, so 7.5x. I guess if you kind of work backwards and try to get to the implied gathering and processing fee on our math, it's around $2 per MMBtu, which seems a little bit high, I guess, compared to others. Maybe if you could just unpack, I guess, what's behind that fee. Is that math correct? And how does that fee expect it to evolve as you ramp up volumes here?

Yes. This is Sheridan. And one thing is we don't want to break down the fee or tell you what the fee is. But what I would say is that we have -- it's at market rates. We have long-term contracts, we said 12 years. So that fee is locked in for a period of time under our acreage dedication as we continue to grow. But we think we're in a competitive area with the services that Pierce talked about, how we have bigger pipe in the area for capacity for some constrained systems out there, we think we can grow our volumes even beyond what we're showing inside of this in this acquisition.

Got you. And then just a point of clarification. So in terms of the Y-grade volumes, I guess, the ones that are coming out of the Sundance plants are moving on West Texas already. When you think about the synergies, is it Cassidy plants where potentially that could be incremental and come on to West Texas LPG? And then I guess just beyond transportation, what about on the frac side? How much of that is already being moved on to your systems? Just trying to understand the opportunities there on the commercial side.

This is Sheridan again. When I think about synergies on this system, first thing you think about is these 2 systems sit on top of each other in a lot of the areas. So we're going to have a lot of capital synergies avoided where, as Pierce said, we could do things much cheaper together than we could be apart. We'd be able to utilize our capacity on -- our existing capacity in the Midland during the short term that we can move some of this offload volume on to there and some of the new growth volume as it comes on going forward. And then obviously, there's going to be some operational synergies as well. So not only we're going to see synergies on directing NGLs to our system, we're also going to see capital synergies and operational synergies.

We'll move to our next question from Jeremy Tonet with JPMorgan.

Just wanted to check, I guess, for the CapEx build-out for the processing plants, what have you that you said, how much capital is left to spend there? And is that in the deal acquisition multiples you quote?

Yes. The capital -- this is Randy. The capital that we expect to spend in 2027 to finish Cassidy is about $130 million.

And Jeremy, the 7.5x multiple does not include that $130 million.

And is there any in '28 capital to get to that multiple in '28?

There's very, very little. It would be basically just a few bills that are rolling over, about $13 million probably coming in, in 2028.

Our next question comes from Manav Gupta with UBS.

I just wanted to go back to the option of buying back at the eighth anniversary. Slide 11 is very informative. I wish I had a Y-axis on it. So help us understand a little bit how you're thinking about the ability to execute the buyback at the end of 8 or 10 year whenever you think it would be the best chance of closing that.

Well, I think the trajectory that we have in the presentation is illustrative, but I would say it's a pretty good picture of our expectation of how that will amortize. So it's generally very close. That assumes that we're using 15% of cash flow. As many of you have modeled pretty meaningful stock buybacks in the years '28, '29, '30 as we were generating significant free cash flow. We have the ability to push that up to 20% in any quarter that we want to or as many quarters as we choose. So we'll look at that as another opportunity to return capital and increase the earnings power for the rest of the common equity. The ability that we lean into that a little bit, it will be done potentially inside of that 8-year window.

We'll take our last question from Keith Stanley with Wolfe Research.

I wanted to ask on the 3.25x pro forma leverage disclosure for next year. It seems a bit high to me. So if you had $33 billion of debt at the end of Q2, you're paying down $5 billion with this deal, so that's $28 billion. If you divide by the 3.25x leverage, that's $8.6 billion of EBITDA next year with Brazos. Am I thinking about that right? Or any major pieces I could be missing in that analysis?

I think you're -- we've got a lot of working capital has been going around with commodity prices here. So we might have just a little bit more debt than you are factoring in. But I think you should look at -- we said approximately 3.25x, and we said that over time, we expect to maybe be under 3.25x. So we think we're going to comfortably achieve that statistic and things are going well, we may do better.

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

Yes. Thank you, Taren. We are headed into employee meetings now, but the IR team will be available throughout the day for any follow-ups. Thank you all for joining, and have a great day.

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 Second Quarter 2026 Earnings Call. As a reminder, this call is being recorded. [Operator Instructions]

At this time, I would like to turn the conference over to Megan Patterson, Vice President, Investor Relations. Megan, please go ahead.

Thank you, Jess. Welcome to ONEOK's Second 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. Good morning, everyone, and thank you for joining us today. Joining me on the call are Walt Hulse, our Chief Financial Officer; Randy Lentz, our Chief Operating Officer; and Sheridan Swords, our Chief Commercial Officer. Yesterday, we reported second quarter earnings and raised our 2026 financial guidance for the second time this year, reflecting strong year-to-date performance and continued momentum heading into the back half of the year.

Our second quarter results were driven by record NGL throughput volumes, strong refined products demand and continued volume growth across our systems. The quarter highlighted the positioning of our asset footprint, the value of our integrated platform and the outstanding execution of our employees. The broader energy backdrop remains constructive, but the more important point for ONEOK is that we are converting that backdrop into visible growth. Our footprint connects key supply basins with domestic and international demand across natural gas, natural gas liquids, crude oil and refined products. The connectivity across our business segments gives us multiple ways to grow earnings, optimize existing assets and allocate capital toward opportunities with attractive returns. Importantly, these opportunities are not confined to a single commodity or region. Our integrated system enables us to create value across multiple demand drivers, a differentiator for ONEOK. Our confidence is reflected in our long-term outlook.

We continue to target mid- to high single-digit adjusted EBITDA growth over the next 5 to 7 years, supported by 3 factors that are increasingly visible. Recently completed and soon-to-be completed projects drive structural growth spanning Permian Basin processing capacity, Powder River processing capacity, Mid-Continent fractionation capacity, refined products expansions and natural gas transportation and storage capacity and LPG exports. operating leverage available across our assets, requiring little to no capital investment and allowing us to be flexible to customers' needs and timing.

And finally, a growing pipeline of high-return organic projects, bolt-on acquisitions and commercial optimization are creating additional investment opportunities across our system, where commercial discussions are improving our confidence in timing, scale and returns. Our long-term strategy remains grounded in the same principles that have gotten us to where we are today, operational excellence, financial discipline and a value-driven approach to capital allocation.

With that, I'll turn it over to Walt for a financial update. Walt?

Thank you, Pierce. As Pierce mentioned, our second quarter performance and strengthening outlook across our business supported a second increase to our 2026 financial expectations. We now expect a 2026 net income midpoint of $3.6 billion, a diluted earnings per share midpoint of $5.68 and an adjusted EBITDA midpoint of $8.35 billion. This represents net income and adjusted EBITDA increases of $150 million and $250 million, respectively, compared with our original guidance provided in February.

At the segment level, natural gas pipelines and refined products and crude continue to perform towards the upper end of the adjusted EBITDA ranges provided in our original guidance. Natural gas liquids and gathering and processing remain well positioned through the balance of the year. Across the portfolio, organic volume growth, EBITDA from recently completed projects and attractive hedging and commercial opportunities are providing momentum in the second half of the year and into 2027.

Our 2026 capital expenditure guidance remains unchanged at $2.7 billion to $3.2 billion. We expect capital spending to accelerate through the second half of the year as several major projects move towards completion, bringing us towards the upper end of our CapEx guidance range.

Turning to the second quarter results. ONEOK reported net income of $965 million (sic) [ $967 million ] or $1.53 per diluted share, a 13% increase year-over-year. Adjusted EBITDA totaled $2.12 billion, up 7%, driven by volume growth and strong segment level performance. We continue to expect earnings to largely follow the normal seasonal cadence of our business as we move through the remainder of 2026. With the tailwinds, I suggest -- I just mentioned supporting second half results.

Our overall financial position remains strong and continues to provide the flexibility to invest in the business, return capital to our shareholders and pursue opportunities that create long-term value. As additional guidance on the application of the One Big Beautiful Bill and the inflation reduction act has become available, we've continued to evaluate the impact of the tax legislation, particularly as it relates to acquisitions and bonus depreciation. Based on our latest analysis, we now expect approximately $2.6 billion of cumulative cash tax benefits compared with the approximately $1.5 billion we previously discussed. These additional benefits, combined with our existing tax attributes, are expected to defer meaningful cash tax payments until 2031, extending our cash tax runway by approximately 2 years and further enhancing future free cash flow generation. Higher earnings and improved free cash flow also support continued progress towards our long-term leverage target of 3.5x debt-to-EBITDA.

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

Thank you, Walter. Our teams continue to execute at a high level throughout the second quarter while maintaining focus on safety, reliability and customer service. Performance across the system remains strong, supported by increasing customer activity, improving asset utilization and contributions from recently completed projects. As volumes grow across our footprint, we're seeing the benefits of the connectivity and scale of our assets. We continue to advance project portfolio. And as of August 1, our Denver area refined products expansion was placed in service. This project adds 35,000 barrels per day of capacity into one of the fastest-growing markets in our footprint provides a new direct jet fuel connection to Denver International Airport.

In the Permian Basin, we continue to expand processing capacity to support growing producer activity. Following our recently relocated 150 million cubic feet per day plant in the Midland Basin, we remain on track to complete 110 million cubic feet per day of Delaware Basin plant expansion projects during the third quarter. Additionally, based on production outlooks in the basin, we've increased the capacity of our Bighorn plant to 400 million cubic feet per day from an initial capacity of 300 million cubic feet per day. Bighorn remains on schedule for completion in mid-2027. Upon completion of our Permian completion, our Permian processing capacity will increase to nearly 2.4 billion cubic feet per day.

In addition, along with our initial 60 million cubic feet per day cutter plant in the Powder River Basin, which was previously announced, we've begun construction on another 120 million cubic feet per day cutter 2 plant, which we expect to be online in the first quarter of 2028. And finally, Phase 1 of our Medford fractionation project remains on track for completion during the fourth quarter. Bedford Phase 1 will add 100,000 barrels per day of Mid-Continent fractionation capacity with Phase 2 expected to be completed in the first quarter of 2027. Looking ahead, the projects in service over the next several quarters are expected to add visible earnings, increased system utilization and support our long-term growth outlook.

With that, I'll turn the call over to Sheridan for a commercial update.

Thank you, Randy. Commercial activity remained strong during the quarter, supported by favorable fundamentals across all 4 of our business segments. We delivered solid volume growth across our integrated system driven by increased customer activity, healthy domestic and international demand and continued production growth in key producing basins. .

Starting with the Natural Gas Liquids segment. Rate throughput volumes increased 7% year-over-year, with growth across all regions. Utilization continued to increase across the system, supported by improved seasonal demand and producer activity. The Gulf Coast Permian region led performance, increasing 15% year-over-year driven by increased production volumes and the continued ramp-up of recently connected third-party plants. In the Rocky Mountain region, NGL volumes increased year-over-year even taking into account a contract roll effective at the beginning of the quarter, which was previously discussed and assumed in guidance. This was more than offset by growth across the region and continued strength in ethane recovery. Higher NGL pricing and export demand continued to support ethane recovery across all regions, and we expect these dynamics to remain favorable into the third quarter.

Global NGL demand remains strong. supported by growing petrochemical demand and continued interest in securing long-term access to reliable U.S. supply. We're pleased to announce that we've reached our targeted contracting threshold at 80% for our 200,000 barrels per day of LPG export capacity, which is currently under construction as part of our export dock joint venture. The capacity is supported by high-quality counterparties and customer interest remains robust, including discussions that extend beyond the initial contracted period and into the next decade. This underscores both the growing demand for U.S.-sourced LPGs and the value of the terminals advantage locations.

Turning to the Refined Products and Crude segment. Demand fundamentals remained positive during the quarter. Year-over-year Refined Products volumes shipped increased 8% and supported by gasoline and diesel demand, high refinery utilization and refinery maintenance dynamics. Blended volumes were also strong during the quarter driven by increased system throughput. Higher gasoline volumes allow us to blend more product and further optimize operations across our network. While our hedge position limited our ability to fully capture the benefit of wider spring blending spreads, we have secured additional fall hedges at higher prices and extended new hedges into spring 2027, improving visibility into future blending margins.

The location and flexibility of our Refined Product system and our ability to clear barrels in a dynamic market remains significant competitive advantage. As refinery utilization remained high and product flows continue to evolve, our unique bidirectional connectivity between the Mid-Continent and Gulf Coast allow us to connect supply with the strongest demand markets, including an increasing pull for U.S. refined products and exports along the Gulf Coast.

Demand for our marine export services also remain robust. At our Sabre crude export joint venture Throughput increased approximately 20% compared with the first quarter included record oil -- crude oil loadings in May. The facility remains highly contracted and under take-or-pay agreements for the foreseeable future. Midland crude gathering volumes increased 10% compared with the first quarter reflecting continued strength in this higher-margin business. Rigs have steadily increased on our Midland crude gathering position throughout the quarter and we currently have more than 30 rigs operating on our acreage. In addition, strong Houston refining and export demand drove outperformance on our long-haul crude oil pipelines.

Moving to the Natural Gas Gathering and Processing segment. Volumes increased across all regions compared with both the second quarter of last year and the first quarter of this year. Producer activity remains healthy across our footprint and development plans continue to track largely in line with expectations communicated throughout the year. We maintained good visibility to the remainder of '26 and into '27. In the Permian Basin, our recently added Midland capacity expansion positions us well to support increased development activity in the Barnett formation. While our planned projects in the Delaware Basin provide additional capacity to support anticipated growth into 2027 and beyond. We currently have 11 rigs on our acreage in the Mid-Continent and 13 in the Rocky Mountain region, up 2 rigs in the Rockies compared with last quarter. Both areas experienced a seasonal pickup in activity during the second quarter, driven by higher well completions.

I'll close with our Natural Gas Pipeline segment, where continued transportation demand and favorable market conditions drove another strong quarter. While how the key location price differentials continue to benefit this segment during the second quarter. We expect lower earnings in the second half of the year as Permian takeaway capacity enter service and differentials narrow, consistent with our full year outlook and guidance assumptions. Looking forward, power generation, LNG exports and industrial development continue to support increasing natural gas demand across our footprint. We continue to advance commercial discussions supporting multiple large-scale data center developments. While these projects have not yet reached FID continued commercial project reinforces our confidence and the scale and durability of the opportunity.

From the power generation perspective, we were recently awarded a supply agreement for 1 gigawatt of power plant demand further expanding our participation in a growing source of natural gas demand, supporting electric generation has long been a core part of our business. Our intrastate natural gas pipeline system is already directly connected with numerous power plants across our footprint and is well positioned to serve future demand growth. Pierce, that concludes my remarks.

Thank you, Sheridan. Randy and Walter. As we step back, it's clear that demand fundamentals remain strong. in the long-term outlook for U.S. energy infrastructure remains compelling. And as we look across our business, the message is straightforward. We've raised guidance for the second time this year. extended our cash tax runway, advanced key projects and strengthen visibility into earnings growth and free cash flow through 2027. Our integrated multi-molecule platform positions us to capture opportunities across commodities, regions and demand drivers while maintaining financial and disciplined flexibility. And most importantly, none of this would be possible without the dedication of our employees and their commitment to safe, reliable and disciplined execution.

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

[Operator Instructions] Our first question comes from Spiro Dounis with Citi.

I want to start on the growth strategy from here. Because, I think you had talked about aspiring to grow mid- to high single digits over the next few years. And curious just to get more color on that front. Specifically, how much of that growth could be underwritten by filling up the white space that you mentioned on the current system versus building out new infrastructure? You mentioned the growing backlog of projects coming. So how should we think about maybe the timing of when those projects could come to market? And maybe which verticals you see probably getting the most attention.

Okay. Spiro, I'd start out by saying that it's not one thing that's driving this -- the conclusion for us. We actually have a multi reinforcing growth drivers. Our assets are positioned in these premier growth basins in the U.S. and especially in our export markets. And the growth across our footprint is actually underpinned by basically 5 things, not just filling the white space that you mentioned. It's the continued strong Permian Mid-Continent and Powder River growth and the associated natural gas liquids. It's the stable Bakken growth through improved well productivity. It's the rising U.S. LPG export market, and there's a shift definitely in the global crude oil demand to a more reliable and a more resilient supply. And then you've got through LNG exports driving the natural gas increase across the United States is driven by the growing 30 Bcf a day or over 30 Bcf a day LNG export and your domestic natural gas fire generation and industrial demand.

So these facts all give us the confidence that we have to that high single-digit EBITDA growth over the next 5 to 7 years. So it's not just one thing, it's a multitude of things, and it's across all 5 of our business segments.

Got it. Second question, maybe if you shared in just zeroing in here on the NGL segment. Looking for more color on the dynamics around the quarter. Volumes were really strong, as you pointed out, but margins may be a little bit softer overall. You talk about some of the dynamics that were driving that this quarter? And how you're thinking about margins going to the back half of the year? Should they stay at these levels? Do you think there's a reason to think you could see expansion?

Yes. As we talk about the margins, we did see a little bit of reduction in the margin -- overall margin on certain parts of our system, and this was really driven by increased ethane. We saw versus how much the increase in C3+ we had. That happened in all 3 of the seconds, Permian, Mid-Continent and the Bakken, where especially discretionary ethane out of the Bakken comes at a much lower rate than what the C3+ at full rate is getting out of the Bakken. And like I said, we did see both the increase in C3+ in the Bakken, but we also saw a greater increase in ethane. And that also became apparent in the Mid-Continent, where we had a large increase in ethane in the Mid-Continent. And those rates are tiered rates that we've had for a period of time where we charge a higher TNF rate for the C3+ than we charge for the ethane, even at full rates. .

And so as that more ethane comes on, it can have a little bit of effect on our overall margins that we have in there. But we are seeing a lot of increase of [indiscernible] across our system. And one area I'd kind of note is the Permian on volume where we've seen here in the last month or 2, a strong increase in our volumes, a substantial increase in our volumes. And really look at it, it was kind of tied to the way Waha to Katy spread. As that spread came in and Waha became positive. We saw a lot more volume than we had anticipated behind our NGL system come on in that area. So we've seen July has been a great month and August is falling suit on good uptick in volume on our NGL system.

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

There's been some talk from some E&Ps year-to-date around reducing their midstream costs. In that context, can you update us on the duration of your NGL TNF contracts out of the Bakken? .

Yes. Our rates of the bucket are still extended for a period of time. We have -- really don't have anything of material coming up until late this decade and most of the stuff is into next decade. So we feel very good about our NGL rates out of the Bakken at this time.

And refined product prices and PADD IV have continued to rise year-to-date versus PADD. I believe you've said before that your Denver pipeline is mostly long-term contracted, but is there a meaningful exposure to the spread at these price levels? .

The 35,000 is signed up by firm take-or-pay contracts. Obviously, there may be a little opportunity that always our operating team finds a way to squeeze a little bit of volume out there that we may be able to get -- be able to enjoy a little bit on a spread that happens there, but it's under majority almost all of this is under long-term contracts -- long-term firm contracts. .

We'll go next to Jeremy Tonet with JPMorgan.

This is Vrathan Reddy on for Jeremy. Just potential for additional egress out of the Bakken. Just curious if you could speak to your outlook for the ethane recovery at this point, maybe ONEOK's positioning against that backdrop?

Yes. I mean our egress for NGLs out of the Bakken is strong. We still have -- we're running up around sometimes up to 500,000 barrels a day, which gives us plenty of more capacity to be able to move in there, and we can flex on the ethane if we want to. So we don't really see egress out of the Bakken being an issue in our forward plan. .

Got it. And as a follow-up, I want to dive deeper on the Mid-Con. It looks like decent producer activity within the region, there might be a contract for all next year. But curious if you could dive a little bit deeper into your outlook for the balance of '26 and into '27.

Yes. We have -- continue to have contracts that roll in the Mid-Continent different areas, and some of them were put on at higher time where margins were higher. So there will be a little bit of could be some of these contracts come back to more of what we see the market is at this time. But typically, anytime we're dealing with customers on that, there's a give and take in areas that we work with. And so there is value shifted back and forth between different basins as we've talked about as we bundle rates with our large contractors. But most of our contracts in the Mid-Con still have some term on them. For a period of time, nothing is coming up. here in the next month or 2 or even into next year. .

This is Pierce. The only thing I'd add to that is the fact that any sort of contractual movement, we've already factored that into our guidance numbers. So that's fully baked in to market rates.

We'll go next to Praneeth Satish with Wells Fargo.

I guess just turning to the Permian. So obviously, you're seeing good growth there, strong demand. When we think about West Texas LPG specifically, how much remaining uncontracted capacity do you have on this system, and how much more room do you have there to support the growth that you're seeing in the Permian? And then maybe just sticking on Permian NGLs. If I remember correctly, with some of the legacy EnLink volumes, they're moving on relatively higher-cost NGL transportation paths. And so as those contracts roll over, to what extent can those be migrated to West Texas LPG? And what's kind of the time frame for that?

What I would say on your first question is we've come out and said that with the expansion, the mainline expansion of West Texas NGL pipeline. It's -- we have capacity up to 740,000 barrels a day. So with that, and what we're seeing today, we still have plenty of capacity to meet the demand that we have coming on, both from our processing plant expansions and the growth that we're seeing from third-party plants are coming on as well as well as the opportunity to grow our processing even further than we have announced into the future.

So we think we got a very good position there. A lot of operating leverage, as you would say, that we could move additional NGLs on that system. So we don't see have to expand that for a period of time.

And what was second -- what was your second part of the question?

The second one was on the legacy EnLink volumes and recontracting and bringing some of that on to West Texas LPG.

Yes. As I said, there's a little over 50,000 barrels a day that we control that was brutally contracted under EnLink on another third-party pipeline -- and those contracts will start rolling off here starting a little bit later, '26 and '27, '28. And all that volume will come directly over to our NGL pipeline when they roll off.

Okay. Great. And then maybe going back to -- I think it was Jeremy's question, but I think you kind of took it as NGL egress. But I think his question in mind is -- there is a few proposed gas takeaway projects being proposed in the Bakken and seems like at least one of them may move forward, sizable projects. So I guess the question is if gas egress improves in the Bakken, how does that impact your outlook for basin growth, BTU levels and really ethane recovery? And could you see more upside from potential more production growth kind of offsetting maybe some downside from lower ethane recovery. Just how do you think about that?

Yes. I think a little bit on each time with the producers get a little bit better netbacks than anything else. So that helps them to increase the production or have more incentive to increase their production. In terms of our ethane -- discretionary ethane that we have coming out of the Bakken. Really it's based on a lot what's coming out of Canada and what's held back out of Canada is still the incremental barrel incremental mcf to come on the system. So we still think that on the ethane side will be a nice spread for us to enjoy on the discretionary side as we continue to go forward into the future. .

We'll go next to John Mackay with Goldman Sachs. .

I want to go back to some of the questions around the longer-term growth outlook. Pierce, I appreciate the kind of different drivers you called out there. Just curious if you could touch a little bit more on kind of the incremental growth spending kind of where projects could fit in there? And what you think a kind of run rate growth CapEx budget could be like to support that outlook? .

So I appreciate the question. I'm going to throw that question to Walt. the capital spending update there.

Well, as we've been talking about, we have a pretty nice backlog that is building. We've got quite a bit being completed here in '26 and '27, all of which will then bring on that EBITDA going forward. The backlog that we have is more in the midsized projects. We don't have any $1 billion plus right now on the horizon. So that should moderate our CapEx from the current levels. down into that $2 billion, $2.5 billion kind of run rate going forward. Of course, our commercial team is always out there looking for great opportunities. And to the extent we find it, we'll clearly jump on them. But I think that with that $2.5 billion run rate, call it, you're going to see some very significant free cash flow still coming to the bottom line.

I appreciate that. And maybe just a follow-up for me. You've talked a couple of times in recent calls around some of these gas laterals to feed BTM or kind of broader power gen. Could you just talk a little bit about kind of what the commercialization process has been like so far? And then maybe tying it into your last comment right there, that kind of run rate level of growth CapEx, how much of that could be going towards this vertical?

Well, I'll take the first part on the on AI data centers and power gen. Obviously, in my prepared remarks, we talked about that we have secured 1-gigawatt power gen supply contract that will be the supplier of natural gas into that system. It's a really nice project. It's not high capital. I mean it's over $100 million of capital. We'll have to spend at a very nice return at firm demand. We also are in late stages of discussions with a couple of other opportunities to be able to supply AI data centers no doubt that metalization has taken a little bit longer than what we had anticipated on some of these projects.

But I think we're seeing that across the board where it just takes a little bit longer time to get them across the finish line. but we're feeling really good about our position, especially where they're at. We have a strong competitive position, and that's why we've been able to advance these discussions as far as we have.

And then on the capital, I would just say that those types of projects are really what I was talking about there kind of singles and doubles. They're in that $100 million to maybe $400 million or $500 million top end -- so fit really nicely into our capital budget going forward. And then clearly in Randy's remarks, he went through a list of other projects that we've got underway, all of which are very attractive and maybe doubles and triples there, a little bit bigger.

We'll go next to Theresa Chen with Barclays .

Given the growing global focus on energy security, reliable supply, you noted increasing commercial traction for the LPG export facility. How do you see the opportunity set for exports broadly evolving from here, both in terms of the LPG export project as well as brownfield expansion opportunities and/or recontracting to upside on your existing liquids to export infrastructure.

Well, I mean, honestly, we are very satisfied, very excited about reaching our threshold on the LPG export dock. And as I mentioned in my comments, we actually have started conversations with potential offtakers that want to start looking at when these contracts roll off into the next decade and securing that going forward. We have seen since the war that there's been a lot of additional new entrants wanting to talk about the security of the U.S. supply for both LPG and crude oil. We talked about our Seabrook export dock is 100% contracted to the foreseeable future of the firm take-or-pay contracts. So we are seeing growth across liquids demand.

One thing we don't mention very often is our refined products export capacity. We are seeing good volume growth on that, good pulls on that. very strong, which is pulling obviously volume throughout our whole system down there to go forward. So we see that opportunity to continue to grow. Whether or not it goes forward anymore, as I said, on the LPG side, we kind of want to get this up and going and to our customers that we can operate this at the level and reliability that we promise them. for. But we continue to look and see if there's something else out there and continue to engage with customers and continue to go more, but there's definitely a resurgence of people wanting the security of U.S. energy supply.

Theresa, this is Pierce. Some of that upside could be in that extra 20% in our producing community wanting that full wellhead to water pull. So that's one of the other reasons that we left that position open, not only just for operational reasons, like Sheridan said. But looking at potential upside for us in the future, but that grounding of that 80% was important for us.

With the Denver refined products pipeline expansion now in service and incremental commentary from the downstream community about moving additional volumes from PADD 4 into PADD V over time. How is your view of PADD IV regional supply and demand balances evolved or the Denver area and beyond? And as PADD IV becomes tighter, what opportunities does this create across your infrastructure footprint that Mid-Con to Rocky movement? And how are you thinking about potential for further expansion on that Denver pipeline system beyond the jet field movement?

Yes. We're excited about how getting this pipeline up and operating. It's been -- we've been working on for some period of time. Operations done a great job to get it on, on time. As we've noted, we brought that on. We laid a 16-inch pipeline that has upwards of possibly 200,000 barrels a day of capacity. We're only running 35,000 barrels a day on that. We've seen for a period of time that PADD IV could need more volume going forward, and that could be supplied by this pipeline. There has been some talk of some projects getting into the Salt Lake City that we feel we will play a part in those, be able -- that we can get the capacity there. the cheapest and the quickest as we have set that pipeline up for expansions going forward.

So getting this pipeline was very critical to us. to show that and be able to show everybody that we can expand it and be able to supply that growing demand in PADD IV.

We will go next to Keith Stanley with Wolfe Research.

First, I wanted to clarify on the mid- to high single-digit EBITDA growth. So Walt, it sounds like you're saying that's tied to $2 billion to $2.5 billion a year -- any color you can give on what that assumes for volume growth? And if that includes or does not include any bolt-on M&A of any kind?

Well, it's really a combination of future CapEx and then to quote Spiro, there the filling the white space. We've got plenty of operating leverage across our businesses. So as we are able to do brownfield expansions off of that, we'll continue to grab opportunities at really attractive capital. But -- coming back to some of the drivers on that here in the short term, and we think going forward, Sheridan mentioned that the world looking for diversity of supply we see very significant volume growth in our refined products go into the Gulf Coast, and that could be really meaningful for us because it's pulling tariff across the system. We've got rigs up in every one of our basins and visibility to more coming. Commodities were well hedged here in '26.

So we didn't really get a big benefit from this pop here in '26. We'll enjoy it on the incremental supply that we get above what we had hedged, but we're going to really see that benefit as we roll into '27. And then one that we found really interesting, while we did benefit from the Waha a Katy spread, as that narrowed down, we really have seen a nice pickup in NGLs from volume that was shut in behind our system and mostly on the third-party plants. So with the constructive backdrop here, we're confident in the new guidance the momentum holds, we might even be updating you in Q3.

Great. The second 1 on ethane recovery. Is there any way to quantify how much incremental ethane recovery you saw with the market dynamics in Q2 and I guess, the Bakken and the Mid-Con, it just seems like a pretty meaningful boost to volumes based on the change in rate.

Yes. I would say we saw a significant increase in ethane recovery in the Mid-Continent. It's probably 1 of the biggest 1 at full rates and which has been good. there were still up in the Bakken because of the difference in rate that you have between a full rate for C3+ versus the discretionary ethane that we bring on. A little bit of volume can affect that by -- I think it was down $0.01 or so. It can affect that with those rates that we have there. So we saw good than recovery in the Bakken. And then obviously, in the Permian, we also saw a little bit before that they're coming on the Permian. Actually, the growth in the Permian was much more weighted to the C3+ side. .

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

I think in your prepared remarks, you talked about upsizing some of the projects that you had previously announced. So I was curious, is that a result of more customers coming in or just your existing customers kind of increasing their demand for the processing capacity. .

Yes, this is Randy. We've got a little bit of both. I mean, we have existing customers that are really performing as Walt mentioned, too, I think the Waha spread there narrowing has helped a lot. We're seeing that increase, but we're also seeing our commercial people do a really good job of doing additional deals and interest on existing customers to increase it. So it's a little bit of both.

Okay. And then with the mid- to single-digit EBITDA growth that you outlined for the foreseeable future. I was curious how does that translate into the EPS growth rate. Obviously, it seems like your capital spend is going to be fairly capped at least from the organic growth projects. So I was curious if you could clarify that. .

Yes. We would think that our EPS growth rate should exceed that EBITDA growth rate, especially as we move into more free cash flow and potentially take the opportunity to buy in some shares. So we're very constructive on the EPS growth rate.

We'll go next to Manav Gupta with UBS.

Could we get a little bit of an update on your Permian processing plants that are set to come online in the near future?

Yes. So in the processing plants coming online in the near future in the Permian, we have here in the third quarter, as Randy outlined in his comments, we have 110 million a day coming on in the third quarter. That will be in the Delaware. And we -- that they're going to fill up pretty quickly. That 110 million a day is going to feel pretty quickly. We have good line of sight on volume growth in that area. The Shadowfax plant in the Midland is already up and going, and we'll be filling it as well quickly. Then we have the Bronco plant that will be also out in the Delaware, which will be into '27. We will have that later into '27. That will be filling as well. And that's the 1 that Randy had mentioned that we originally FID at [ 300 million ] a day due to what we're seeing with producer activity and commitments we have on our system. We've already upsized that. It was a very cheap upsize to [ 400 million ] a day. So that's making that project even look even better out there.

Perfect. I just want to go back quickly to the '26 guide. Help us understand what could drive further guidance revisions as you kind of hinted to -- and what could put you towards the top end of that guide of $8.5 billion. .

Well, I think that we're seeing a nice pickup in producer activity. Clearly, we've got a constructive market in the Refined Products side. with a healthy spread on our upgrades there with our bond to butane spread. And the fact that we're seeing rigs across the board coming in really nice strength in our Crude Gathering business with rigs coming in there. So it's really across the system, we're seeing our customers wanting to take advantage of these slightly higher prices and positioning themselves for growth through '26, but really strongly into .

One thing I may add to that a little bit is that is we came in pretty hedged in '26 on Refined Products. But with this increased volume we're seeing across our system, that is allowing us to hedge even more or allowing us to blend even more, and that was not hedged at the lower prices. We're able on this incremental volume able to capture that at a higher rate going forward. And if that volume continues into the later half of this year, the strong one that we think could possibly happen, that's another thing that gives some tailwinds. .

We'll go next to Julian Dumolinmith with Jefferies.

This is Alex [indiscernible] on for Julian. Just a quick question and maybe just a point of clarification. How much would you say, if any, of the mid- to high single digit is predicated on those bolt-on acquisitions that you guys talked about? And then also just where are you seeing the best opportunities for bolt-on M&A in across your footprint?

So this is Pierce. I would say that the majority of those -- of that growth is the organic. It's everything that I mentioned. It's about continuing to optimize our systems. It's continued to take advantage of synergies, continuing to, again, "Spiro", fill that white space with very little capital. That's the majority of it. As it relates to the M&A, -- my message there is the same that it's always been, which is we're going to be intentional and disciplined about what it is that we're doing. And we're always looking to expand and extend our footprint in any of our any of our basins. So wherever those opportunities present themselves, we're going to be looking at those.

Got it. That's super helpful. And then just quickly on -- for that mid- to high single digit, what is the implied sort of Bakken volume growth underpinning that? Is it sort of similar to what you guys talked about at the beginning of the year low single-digit kind of growth.

Yes. That's right. We're staying with that.

We'll go next to Gabe Daoud with Truist Securities.

Thanks, operator. I wanted to go back to the volume side. You had mentioned in the Permian, seeing some incremental gas show up as the spread Katy-Waha spread significantly improved. Just curious, have you quantified that number? I'm just trying to think through how you guys at least maybe in the Permian, could land at the high end of your volume guide of 1.7 Bs .

Yes. What I'd say is that we've seen the large -- probably the largest on our NGL coming from third-party plants. Obviously, we've seen some on the we need to see if that continues to go forward. But it has been substantial. It has -- at times, this approach as much as 100,000 barrels. .

Got it. On the NGL side. Okay. Okay. Great. That's helpful. And then I guess just as a follow-up, the mid-single-digit EBITDA growth number that you guys are highlighting, if we were to just assume rigs on your system today or the carry through to '27. Does that get you there on the growth side from a volume standpoint? Or is there also like the expectation that rigs continue to be added as we progress through '26 or '27 .

I'd say in some areas, there is a little bit of addition because we've talked to producers about adding more rigs on there. I mean, we know for sure, there'll be another rig added into the Bakken. It's an area that we know what's going in there. But it's a -- it's either off of what we rig count we have today or we're talking to producers what is coming in the future. .

Only thing I'd add to that is we tend to exceed it on the rig count as it relates to gas and now that's associated gas with -- so that's some are areas of dedication. But we're seeing significant activity on our dedicated oil gathering dedications. So it's the reason we started including that in our prepared remarks because I think it's meaningful.

Yes. No, that's helpful. We've seen that in the data 2 rigs up quite a bit on what would be tagged as ONEOK gathering. So yes, that's great to see.

We'll take our final question from Jason Gabelman with TD Cowen.

I wanted to go back to the Permian and ask about your processing growth. It seems like some of your competitors are sanctioning plants in beyond 2027 and 2028 and 2029. How do you feel about your processing growth or plant growth potential beyond 2027, given things like needing to lock in some equipment and labor, do you need to kind of FID projects now to make sure they come online to support continued growth beyond 2027? .

Yes, this is Randy. So as I mentioned, we upsized big ore. And we have predicted that we would probably need to do that. And so we were able to take advantage of that at a pretty low capital increase. We've also gotten ahead of buying long-lead equipment that you're referring to. We already have another plant that effectively, we've secured. So we'll be able to put that out into the Permian and deploy that as needed with the growth that we're seeing from existing customers, the plans they have, we're always staying ahead of that to make sure we can perform, and that's what we've done. So we thought we've got a good handle on that.

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

Thank you, Jeff. Our quiet period for the third quarter starts when we close our books in early October and extends until we release earnings in late October. 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 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.