Oneok (OKE) Q4 2025 earnings call transcript

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 Oneok's expectations or predictions should be considered forward-looking statements We have received 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 and forward-looking statements. For discussion of factors that could cause actual results to differ, please refer to our SEC filing.

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 Lentz, our Chief Operating Officer, and Sheridan Swords, our Chief Commercial Officer. Oneok has begun to 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 two and a half years, OneOak has experienced an earnings power step change. In 2025, our net income at triple 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 science.

Second, we have created an integrated platform advantage. The Magellan, Easton, Inley, and Medallion acquisitions will be fully embedded in 2026 across our NGL, the five 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 of 2023, far exceeding our original expectations. We realized approximately 250 million of those synergies in 2025 alone. And through strategic organic expansions, we've built in operating leverage for projects newly completed or nearing completion that will serve contracts in place and allow one of them 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 volume 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. One O combines scale, integration, and fee stability with long-life assets aligned to meet domestic and global energy demand, and management has proven it 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 operations, with PESA growth being a key consideration for the year ahead. Our guidance reflects discipline, 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 will 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 one OAK 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 billion 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%, further reinforcing that commitment. As we progress towards our long-term leverage target of 3.5 times 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 in 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 pace 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 when two third-party Permian NGL customer plants were delayed for the majority of 2025.

The second column in the chart reflects a $125 billion reduction in lower upgrade margin in our NGL and refined products businesses. An example of this would be the narrowing of Arbob to butane spreads in our blending business. On the positive side, we enjoyed strong location differentials such as the Waha to Katy spread in our natural gas pipeline segment.

These differentials added approximately $150 million to EBITDA in 2025. The majority of the $85 billion 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 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. 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 to EBITDA from batching and blending logistical benefits, allowing us to efficiently move NGLs and refined products through the Easton acquisition connections between Mount Bellevue 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 GMB, NGL, and refined products businesses.

We have also not forecasted any gains on debt repurchases of 26, representing the additional reduction of $85 billion, to get us to a forecasted 2026 EBITDA of $8.1 billion for 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. Yeah, 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 in the 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, and crude, and natural gas gathering and processing segments, supported by continued contributions from recent acquisitions, fee-based growth from volumes, and completed projects, and the continued realization of synergies.

As Pierce mentioned, we expect approximately $150 billion of incremental commercial and cost synergies this year, in addition to the nearly $500 billion we've captured since the closing of the Magellan transaction two and a half years ago. Our 2026 capital expenditure guidance assumes a range of $2.7 billion to $3.2 billion, which includes both growth and banking. 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 Plan. 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.

Thank 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 2025, tempered volumes in the natural gas gathering and processing natural gas liquid segments, but this was largely within our expectations for normal seasonality. More recently, winter storm fern caused temporary wellhead freeze-offs and challenging operating conditions, briefly impacting throughput in the first quarter of 26. We estimate January gathering and processing and NGL volumes were approximately 10% below We have experienced no material downtime in our own assets We have already incorporated the storms impacts into our 2026 guidance Now turning to our capital update Our large capital growth projects are progressing according to plan and are currently expected to enter service as anticipated In the gathering and processing segment, our 150 million cubic feet per day shadow facts plan, which is being relocated to the Midland Basin from North Texas, It is expected to be in service by the end of the first quarter.

We expect volumes to ramp up with 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 product segment, the Denver area pipeline expansion remains on track for an expected mid-third quarter 2026 startup. And lastly, phase one of our Medford NGL fractionated 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 an 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 will now turn it over to Sheridan for a 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 GNP 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. Through 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 GNP volumes in the Rocky Mountain region and record liquid-splitting volumes in the refined product 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 pipeline segment once again exceeded the high end of its guidance range in 2025, benefiting from the strategic location of our pipeline systems, specifically in the Permian Basin and Louisiana. The segment'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 liquid 6, we expect year-over-year volume growth across our operations. In the Permian, we expect to connect at least three natural gas processing plants to our system in 2026, including two thorough-party plants and the Shadowfax 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 bonds.

Moving on to the refined products and crude sales. We expect 2026 performance to be driven by steady-based refined products demand, increased asset connectivity, We are assuming a mid-year tariff increase in the low-to-bid single-digit range, inclusive of both market-based adjustments and index-based tariffs, with potential outcomes of the four-grade index review incorporated into our guidance. We continue to see increased throughput into our long-haul crude oil pipelines from our gathering systems as 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 one PCF per year, One Oak 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 key Cherokee, Canistat, and scoop areas. We have 13 rigs currently operating across more than 1 million dedicated acreage in the mid-continent.

This acreage spans high-producing, gas-focused, liquid-rich, and crude place, 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 with 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% in 2025 and 20% in 2024. Gas-to-oil ratios in the basins also continue to naturally rise, supporting a stable long-term outlet 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 from 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 IGER-Express 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.

Agri reflects both supply-side momentum in the Permian and increasing demand pull from LNG exports, industrial demand, and other in-use markets along the Gulf Coast. Separately, we expect to continue to see favorable opportunities to optimize our system, particularly in the permanent basin, 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 near key demand centers and high growth areas to support long-term natural gas demand. Sears, that concludes my remarks.

Thank you, Sheridan and Randy and Walt. As we look ahead, we are confident in one Oneok's position and strategy. The work we've done to integrate assets, build 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, OneOak will celebrate its 120th anniversary. I want to take a moment to recognize the contributions of those who came before us that 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.

Sure, Spiro. Well, I think that, you know, we think that there's a meaningful potential that we're going to see crude prices in that 55 to 60 range. It's got 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. Higher prices are always a benefit to us. But we think we've been, you know, intentional and disciplined as we put these projections together.

And we want to move towards that $8.1 billion.

Mr. Spiro, when I think about commercially where we have typically seen upside in the past, and you mentioned one of them is the discretionary ethane out of the pocket, where our marketing team has done a very good job of being able to lock those in at different periods where they see spreads being wider, not just the average what we see over a year. They've been very successful in doing that. We've also had on the GNP side, especially the Permian, we have a little bit of open capacity. They've been able to have some offloads, some spot offloads 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 grow volume on a spot basis.

We've also seen that on the NGL as we look about, you know, between Conway and Bellevue, that spread at different times of move, and we're able to capture those or lock it going forward. What are the same things that are our fine products with our normal butane to unleaded 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.

Yeah, 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, you know, in the fairly near future, but we still need to go through the process and get those to bed. But it is looking very, very positive on that, and we probably have quite a few that we think are in advanced stages.

Great. I'll leave it there. Good night. Thanks, everyone. Thank you. Thank you.

Michael this is Sheridan I don 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 Iger pipeline system that is above what we need right now for our our forecast was as we continue to go forward but as a forecast for the whole year 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 do see potential upside in that if we continue spreads at where they are now for the rest of the three quarters.

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 at times, 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, you know, if we see higher crew prices, you could see, you know, producers put another rig on or complete, put more completion crews on, then 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 two can swing your forecast or improve it.

Yeah, what I would tell you about that 150 million synergies that was outlined by Walt is they are all identified, and they are in the plan, and they are underway 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.

The first thing on the Denver expansion, yeah, it will come up, as we said, mid-third quarter. It's fully contracted with Taker Pay Voyage, so it 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 two 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 operating leverage into that pipeline we've been out there. When we think about the Sunbelt connector, I had said last time that 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, our extensive connectivity that we have through our system 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 to FID.

Well, Jeremy, clearly the Magellan, we've had the most time to, you know, play through the synergies there, spend a little capital where necessary to make the connections, to 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. And remember, it's just now been a year since we brought in N-Link, and things are going according to plan.

I think that they're at the pace. At the time we announced that transaction, we said that there were some contractual arrangements at N-Link that were 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 onto 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 pace with Magellan clearly leading the way just because we've been at it a little bit longer, and its opportunity set might be a little bit bigger given the overlap of our assets.

No, I think that, you know, the difference in our outlook has been really more, you know, 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. But volumetrically, 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 2027, like the Denver expansion that Sheridan was just talking about, as well as Medford coming on and the Shadowfax plant. So we've got some nice ads throughout 26 that will give us some strength as we roll into 2027, regardless of what the commodity environment is.

I think when we think about on that, I'll just start with a walk-in and walk through it a little bit, and there's obviously in the walk-in we've talked about it for a period of time. We have a contract coming off this year where 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. But in the mid-continent, it is an ethane story, or C3 plus 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 in 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, say in a nutshell, it'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.

Kevin? Well, what I would say is we contracted for that space on Iger and to be able to provide a service to our customers that we're bringing through our gas processing plants to give them an outlet for their gas to continue to go forward. And what 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 not all being used right now, and the extra volume is what we are able to sell at the spread. So as we get into 27, we are predicting that that volume will be used for our GNP business and the natural gas that's coming off our plants to serve our customers.

Well, I think we've come out and said that it's 55 to 60 is what our prediction is going forward. And yeah, at that, at this crude level, we are saying a low single bid to low single digit growth rate for the Bakken volume, both on the NGLs and on the GNP side of it. Obviously, in a higher crude environment, if producers have more cash flows, they're operating within cash flow today, if 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 bucket and be able to continue to grow our own position. Obviously, we have a very, very large position in there right now, so it's really about growth across the whole basin and 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 them toy around with more refracking and reworking older wells that can bring more volume 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 that could be drilled at a lower price environment.

I'll start with the capacity. We still have right now roughly around 300,000 boroughs a day on our West Texas NGL pipeline. Remember, as we continued to loop that system, we finally had to loop the whole thing, and now we're sitting at well over 740,000 barrels of the other system. As we continue, and the question about being able to track third-party volume to our system, there are still GNP operators out there that are not associated with an NGL pipeline that are looking to move on an NGL pipeline. There's RFPs out there today, as well as there's a lot of producers out there that have taken kind rides at existing plants that we are able to contract for that we're already connected to or can be connected to.

So even those plants may be owned by somebody that is associated with the long-haul NGL pipeline. And we 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 entice that volume to come here And with this very advantaged capacity we have on our NGL pipeline and advantaged frack capacity we have at Medford we think we compete for those very well Understood.

Yeah, what I would say is I'll kind of break our natural gas storage opportunities into two areas. One first area is Texas and Oklahoma, more on the legacy OneOak system, and that has mainly been driven by utilities going in there. We've expanded those a couple 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 in-link acquisition, we are completing out the GIS 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 the GIS storage some more. And then there's the pulling in the storage over there. We think that there's an opportunity to grow as well. We have teams, engineering teams and geology teams looking at that to see what we can do to go for. Those are going to be more driven by industrial customers and LNG people that are going to want to need those systems aware, 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.

What I would say is so far through the year, I mean, you've got to be careful it can be sick a little bit through the year, but so far as we come off in the first quarter, we're seeing good demand, especially on our West Texas system, out to El Paso, which is very, very encouraging.

Now, we've 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. So we are seeing some good demand pull across our system.

Sure. Well, the keys are the ones that Randy mentioned that would come here in 2026. The Denver Pipeline Expansion and the Refined Products, the Shadowfax 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 rolling over into the first six 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 a billion dollars on routine growth every year, and then we managed to find $400 million or $500 million of other larger capital projects that our commercial team is always out looking for, and that backlog is, We don't see any real large capital projects like a thousand 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.

Well, when we think about GMP growth in the Permian, you know, 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 forward. 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 able to capture, especially when you think about a lot of these customers' bars and other basins as well. So we feel very good about capturing more volume on the GMP side going forward. So the great customer feedback that we've had and what we've done so far, we have, as I told you last time, we're at the Shadowfax plant and the going we're doing 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 Inlink was operating these assets.

As we think about inorganic growth, I think in the comments we were talking about, we built a platform with the inorganic growth that we've done so far. We're really concentrating at this time on the organic side of it and how do we connect it 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.

Well, 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 GNP business, and we have a systematic program of hedging, and we try to leave only about 25% open on our commodity exposure as we continue to go forward. So as we think about going forward, that's more like 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.

Well, yeah, I mean, it's progressing. The build side of that is progressing as planned. Very satisfied as we were 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 it.

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 two companies. Excellent collaboration.

Well, I think that it's important to recognize that our three-and-a-half times target is a self-imposed target. The agencies for our current credit rating, you know, provide us a little bit more flexibility at a higher debt-to-ebit than that three-and-a-half target. So we believe we have flexibility from a capital allocation standpoint as we look forward and have clear visibility down to the three and a half. 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, you know, 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.

Yeah, that's increased ethane recovery, what you're saying, is we had a pretty good fourth quarter with ethane recovering in there. You know, we're still, you know, in that 30-ish range 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 that's going to be in that 30-ish range.

So Jason, this is Pierce. I was wondering when the M&A question would come up. But 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, you know, our criteria and the questions around that. And we're going to continue to be intentional in this one and our approach to M&A. So if 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, 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.