ONEOK (OKE) Q4 2025 Earnings Call Transcript

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DATE

Tuesday, Feb. 24, 2026, at 11 a.m. ET

CALL PARTICIPANTS

• President & Chief Executive Officer — Pierce H. Norton
• Chief Financial Officer — Walter S. Hulse
• Chief Operating Officer — Randy Lentz
• Chief Commercial Officer — Sheridan C. Swords
• Vice President, Investor Relations — Megan Patterson

TAKEAWAYS

• Net Income -- $3.39 billion for 2025, up 12%, with earnings per share of $5.42.
• Adjusted EBITDA -- $8.02 billion in 2025, representing 18% growth and marking twelve consecutive years of adjusted EBITDA growth, with a 17% average annual rate.
• Fourth Quarter Performance -- Net income was $977 million, or $1.55 per share; adjusted EBITDA reached $2.15 billion.
• 2025 Shareholder Returns -- Nearly $2.7 billion was returned via dividends and share repurchases; quarterly dividend increased by 4%.
• Debt Reduction -- $3.1 billion in long-term debt retired during 2025, including over $1.75 billion in the fourth quarter, resulting in increased balance sheet flexibility.
• Synergies Realized -- Nearly $500 million of total synergies since the Magellan acquisition in September 2023, with $250 million realized in 2025 alone.
• Fee-Based Earnings -- Approximately 90% of 2025 earnings were fee-based, limiting commodity exposure and underscoring earnings resilience.
• 2026 Guidance -- Net income midpoint targeted at $3.45 billion, $5.45 per diluted share, and adjusted EBITDA midpoint of $8.1 billion, supported by volume growth and $150 million in incremental synergies.
• Producer Inventory -- Management identified 5,000 Bakken wells yet to be drilled on dedicated acreage, representing more than 15 years of inventory at current rig rates.
• Segment Developments -- Record Rocky Region NGL and Gathering & Processing (G&P) volumes, record refined product blending, and natural gas pipeline segment surpassing its 2025 guidance high end, driven by strong Gulf Coast demand.
• Large Capital Projects -- The 150 MMcf/d Shadowfax plant relocation to the Midland Basin is expected online by Q1 end; 110 MMcf/d of Delaware Basin expansions targeted for early Q3 completion; Phase 1 of Medford NGL fractionator rebuild (100,000 b/d) to be in service Q4; Denver pipeline expansion coming online by mid–Q3.
• Commercial Outlook -- Three new Permian gas processing plants will connect to ONEOK’s NGL system in 2026; Denver pipeline Phase 1 is fully contracted under take-or-pay agreements for immediate utilization.
• Refined Products Tariffs -- 2026 guidance incorporates a mid-year tariff increase in the low- to mid-single-digit percentage range, reflecting both market and regulatory factors.
• Natural Gas Pipeline Expansion -- The EAGLE FORD GULF COAST JV pipeline is expanding to 3.7 Bcf/d, 100% contracted for at least ten years; storage expansions in Texas, Oklahoma, and Louisiana remain fully contracted.
• 2026 Operating Conditions -- Management expects first-quarter EBITDA to be the lowest of the year due to weather-related volume weakness and seasonality; January G&P and NGL volumes were around 10% below initial expectations from winter storm impacts.
• 2027 and Beyond -- Incremental free cash flow is expected to increase materially after major projects conclude, with meaningful cash taxes not anticipated until 2029.
• Capital Expenditures -- $600 million budgeted for maintenance, about $1 billion for routine growth, and $400 million to $500 million for larger capital projects annually.

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RISKS

• Walter S. Hulse stated, "with EBITDA expectations lower than they were in 2025 guidance, our denominator has not been as strong as we thought it would. So it is going to take a little bit longer than we originally expected. But we are."
• Bakken gathered volumes finished 100 MMcf/d below initial guidance due to reduced drilling activity after crude oil prices dropped from the $70s to the low $60s.
• Two third-party Permian NGL plants were delayed, and a major Bakken contract for 18,000 b/d is rolling off in 2026, tempering volume growth.
• $150 million EBITDA reduction in 2026 guidance is attributable to lower forecasted Waha-Katy price differentials and weaker price realizations for G&P, NGL, and refined products segments year over year.

SUMMARY

ONEOK (NYSE:OKE) delivered 12% net income and 18% adjusted EBITDA growth in 2025 while integrating several major acquisitions and executing on organic projects. Management targets a net income midpoint of $3.45 billion and an adjusted EBITDA midpoint of $8.1 billion for 2026, underpinned by volume growth in the Permian Basin, operational synergies, and the commissioning of large capital projects. Guidance factors in flat NGL throughput due to the loss of a major Bakken contract, ethane recovery dynamics, and conservative commodity price assumptions. Projected increases in free cash flow and the absence of material cash taxes until 2029 provide capital allocation flexibility beyond 2026. The company expects first-quarter 2026 EBITDA to be seasonally lowest, reflecting volume impacts from winter storm Fern, with improvements anticipated as new projects ramp up through the year.

• The EAGLE FORD GULF COAST JV pipeline’s expansion to 3.7 Bcf/d is now fully contracted for at least a decade, supporting long-term revenue visibility.
• ONEOK has achieved $500 million in synergies post-Magellan acquisition, materially exceeding original expectations, and expects $150 million of additional synergy capture in 2026.
• Management confirms "very high confidence" in capturing all incremental $150 million synergies projected for 2026 as they are "identified" and "underway."
• Expanded capacity and connectivity in the Permian Basin and Rocky Region have resulted in record processing and NGL volumes, with further growth anticipated from customer expansions and new plant connections.
• The company indicates that future step-downs in key pipeline spread-based earnings may occur as new third-party pipeline capacity comes online in 2027 and beyond.
• Capital spending in 2026 will emphasize completion of the Denver expansion, Shadowfax relocation, and Phase 1 Medford rebuild, with more incremental project-driven growth thereafter.

INDUSTRY GLOSSARY

• ARBOB: Reformulated gasoline blendstock for oxygenate blending, a commonly referenced benchmark in refined products pricing.
• Waha–Katy Spread: The price differential between the Waha Hub in West Texas and the Katy Hub near Houston, reflecting regional natural gas supply-demand imbalances.
• Take-or-Pay Agreement: A commercial arrangement obligating customers to pay for a certain minimum throughput or service, irrespective of actual usage, increasing earnings predictability.
• Ethane Rejection: The process of leaving ethane in the natural gas stream rather than extracting it for sale, often driven by unfavourable economics.
• Fractionator: A processing facility that separates mixed natural gas liquids into individual product streams.
• Bcf: Billion cubic feet, a unit of measurement for large volumes of natural gas or storage capacity.

Full Conference Call Transcript

Pierce H. Norton: Good morning, everyone, and thank you for joining us today. Joining me on the call are Walter S. Hulse, our Chief Financial Officer, Randy Lentz, our Chief Operating Officer, and Sheridan C. Swords, our Chief Commercial Officer. ONEOK, Inc. has become a diversified, scaled, integrated energy infrastructure company delivering durable growth with a disciplined capital allocation strategy. 2025 was a defining year for ONEOK, Inc. 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 would like to highlight. First, over the past 2.5 years, ONEOK, Inc. has experienced an earnings power step change.

In 2025, our net income attributable to ONEOK, Inc. increased 12% to $3,390,000,000. Our adjusted EBITDA is up 18% to $8,020,000,000. 2025 marked twelve 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 cycles. Second, we have created an integrated platform advantage. The Magellan, Easton, EnLink, and Medallion acquisitions will be fully embedded in 2026 across our NGL, refined products, crude, and natural gas systems, driving scale, connectivity, and commercial optionality. We have realized nearly $500,000,000 of total synergies since closing the Magellan acquisition in September 2023, far exceeding our original expectations.

We realized approximately $250,000,000 of those synergies in 2025 alone. And through strategic organic expansions, we have built in operating leverage for projects newly completed or nearing completion that will serve contracts in place and allow ONEOK, Inc. 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 growth in 2026 and beyond. Our 2026 adjusted EBITDA midpoint of $8,100,000,000 is supported by volume growth, completed or near-completed projects, and $150,000,000 of incremental acquisition synergies.

Related to producer activity, in the Bakken alone, there are 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, Inc.’s combined scale, integration, and feasibility with long-life assets are aligned to meet domestic and global energy demand. 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 integrations, 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 the 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 Walter S. Hulse, Randy Lentz, and Sheridan C. Swords to provide their financial, operations, capital projects, and commercial updates. Walt?

Walter S. Hulse: Thank you, Pierce. I will 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, Inc. totaled $977,000,000 or $1.55 per share, and totaled $3,390,000,000 for the full year, representing a 12% increase compared with 2024 and resulting in earnings of $5.42 per share. Adjusted EBITDA totaled $2,150,000,000 in the fourth quarter of 2025, and more than $8,000,000,000 for the full year. Full-year results included $65,000,000 of transaction costs. During the quarter, we retired more than $1,750,000,000 in senior notes through a combination of redemptions and repurchases. Fourth quarter activity brought our full-year total to nearly $3,100,000,000 of long-term debt extinguished.

In 2025, we returned nearly $2,700,000,000 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 3.5x 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 $3,450,000,000 or $5.45 per diluted share and an adjusted EBITDA midpoint of approximately $8,100,000,000. On page seven of our investor deck, we have provided a bridge analysis from original 2025 guidance issued in February 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 100,000,000 cubic feet per day lower than originally anticipated. This change in drilling pace began in 2025 when crude oil prices dropped from the $70s to the lower $60s range. We also experienced a reduction in anticipated NGL volumes when two third-party plants were delayed in 2025. The second column in the chart reflects a $125,000,000 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 $150,000,000 to EBITDA in 2025. The majority of the $85,000,000 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 $8,085,000,000 compared to our original 2025 guidance of $8,225,000,000. Looking forward to 2026, we see $100,000,000 of EBITDA growth from increased volumes in the Permian and the full year of third-party Permian plant volumes that were delayed in 2025.

The $100,000,000 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 we have previously discussed. We expect asset optimization to add $150,000,000 of EBITDA from 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 $150,000,000 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 G&P, NGL, and refined products businesses.

We have also not forecasted any gains on debt repurchases in 2026, bringing us to an adjusted EBITDA midpoint of $8,100,000,000 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 have added another new slide to our earnings material on page eight 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 $22,000,000 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 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 have 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 and capital allocation flexibility going forward. I will turn it over to Randy for an operational and large capital projects update.

Randy Lentz: Thank you, Walt. I will begin with a comment about the impacts of weather in 2025 and 2026. Winter weather across our system in 2025 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 Fern caused wellhead freeze-offs and challenging operating conditions, briefly impacting throughput in the first quarter of 2026. We estimate January gathering and processing and NGL volumes were approximately 10% below our original expectations due to weather. We experienced no material downtime in our own assets. We have already incorporated the storm's 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, the 150,000,000 cubic feet per day Shadowfax plant, which is being relocated to the Midland Basin from North Texas, 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 110,000,000 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 until 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 start-up. 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 an additional 110,000 barrels per day of capacity in 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.

Sheridan C. Swords: 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. Through a combination of organic investments and strategic acquisitions, we have established an integrated Permian platform that spans all of our products and services. This integration creates multiple touchpoints 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 Region and record liquids blending 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 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 liquids segment, 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 third-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 feeding 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 base refined products demand, increased asset connectivity, continued strong liquids blending, and incremental contribution from the fully contracted Denver pipeline project and other high-return 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 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 are 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, Inc. is well positioned to capture our share of that growth. We continue to see attractive opportunities in the basin beyond those we have already announced. In the Mid-Continent, we continue to expect growth from our strong mix of producers across the key Cherokee, Cana-STACK, and SCOOP areas. We have 13 rigs currently operating across more than 1,000,000 dedicated acres in the Mid-Continent.

This acreage spans high-producing gas-focused, liquids-rich, and crude plays, 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 three- and four-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 basin also continue to naturally rise, supporting a stable long-term outlook for natural gas and NGLs across the basin.

I will 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 for 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 are seeing. Additionally, recent commercial success on our EAGLE FORD GULF COAST joint venture pipeline illustrates how demand pull is translating into new infrastructure.

Strong customer commitments led to an announced expansion to 3.7 Bcf per day from an initial 2.5 Bcf per day, and today, we are pleased to announce that all 3.7 Bcf is 100% contracted for a minimum of ten years. This 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 Coast. Separately, we expect to continue to see favorable opportunities to optimize our system, particularly in the Permian 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. That concludes my remarks.

Pierce H. Norton: Thank you, Sheridan, and Randy and Walt. As we look ahead, we are confident in ONEOK, Inc.'s position and strategy. The work we have 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, ONEOK, Inc. will celebrate its one hundred and twentieth 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 are ready to take questions.

Operator: Thank you. And our first question today comes from Spiro Michael Dounis with Citi. Your line is now open.

Spiro Michael Dounis: Thanks, operator. Good morning, team. I wanted to start with the 2026 outlook, two-part question here. Walt, I was curious if you could talk about maybe where you have built in some conservatism around the guide. I know commodity assumptions maybe look conservatively set. And Sheridan, in any given year, you seem to find opportunities to optimize and find margin. I know a lot of times that is not baked into the guidance. I think Rocky ethane recovery may be one example. Just curious if you could walk through some optimization opportunities you have been able to realize in the past that you think are upside to the guide.

Walter S. Hulse: Sure, Spiro. Well, I think that we think that there is a meaningful potential that we are going to see prices in that $55 to $60 range. It has some geopolitical influence on it now that has 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 higher prices are always a benefit to us. But we think we have been intentional and disciplined as we put these projections together and want to move towards that $8,100,000,000.

Pierce H. Norton: 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 Bakken 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 of what we see over a year. They have been very successful in that. We have also had on the G&P side, especially in the Permian, we have a little bit of open capacity.

They have been able to have some offloads, some spot offloads that 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 in that area, and it can grow volume on a spot basis. We have also seen that on the NGL side as we look at, you know, between Conway and Belvieu, that spread at different times will move, and we are able to capture those from bucket going forward.

And the same thing is in our refined products with our normal butane-to-unleaded spreads that we look to lock 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.

Spiro Michael Dounis: Got it. That is helpful. Thank you, guys. Second question, maybe switching over to the power opportunity. The slides pointed out a step-up in the amount of customers you are 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. Curious if these additional opportunities start to scale you up a little bit?

Pierce H. Norton: 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 are hoping that we can announce something, you know, in the fairly near future, but 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 the advanced stages.

Spiro Michael Dounis: Great. I will leave it there for today. Thanks, everyone.

Operator: Thank you. Our next question comes from Michael Jacob Blum with Wells Fargo. Your line is now open.

Michael Jacob Blum: Thanks. Good morning, everyone. I wanted to ask a couple 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 is no spread in 2026?

Sheridan C. Swords: Yes, Michael, this is Sheridan. I do not 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 Eiger pipeline system that is above what we need right now for our gas coming off of our plants to bring that back to producers. We are seeing good spreads right now, above what our forecast was, as we continue to go forward, but it was 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 seeing—we do see upside and potential upside in that if we can hold spreads at where they are now for the rest of the year, for the rest of the three quarters.

Michael Jacob Blum: Okay. Got it. Thanks for that. 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. Thanks.

Sheridan C. Swords: When we think about ranges in there, we try to put it out there because we are dependent 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 is going to be, and that is what kind of drives it. And then, you know, if you see higher crude prices, you could see producers put another rig on or put more completion crews on, and you could see those grow to more of the higher side of those ranges and beyond.

We are trying to give a range of what we think is reasonable from our experience of operating these assets for many years. Producer activity and how just a simple delay for a month or two can swing your forecast or improve it.

Operator: Thank you. And we will move next to Theresa Chen with Barclays. Your line is now open.

Theresa Chen: Good morning. I 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 $150,000,000 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?

Sheridan C. Swords: Yes. What I would tell you about that $150,000,000 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, we have a very high confidence that we are going to be able to capture these synergies in 2026. What I would say, Theresa, they will come in the same kind of buckets that you see on page nine where we have outlined the different areas where we have been able to capture synergies. We will continue. That is where these are going to come from.

Theresa Chen: Thank you. And as you prepare to bring online the first phase of the Denver refined products 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? In parlaying this to another component of your potential refined product pipeline portfolio, can you provide some incremental color on the commercialization efforts related to Sunbelt?

Sheridan C. Swords: First thing on the Denver expansion, yes, it will come up as we said mid–third quarter. It is fully contracted with take-or-pay volume, 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 2 online as we continue to go forward. We have some momentum in that area, and we are hoping that we can commercialize that sooner rather than later as we go forward, because obviously it is a very nice add-on project. We built operating leverage into that pipeline when we went 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 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 that ties 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.

Operator: Thank you. And we will take our next from Jeremy Bryan Tonet with JPMorgan. Your line is now open.

Jeremy Bryan Tonet: Hi, good morning. 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 have 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 2026 at this point?

Pierce H. Norton: Well, Jeremy, clearly, Magellan, we have had the most time to play through the synergies there, spend a little capital where necessary to make the connections, 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 has just now been a year since we brought in EnLink, and things are going according to plan. I think that they are at the pace.

You know, at the time we announced that transaction, we said that there were some contractual arrangements at EnLink that were going to take a little bit of time to roll off, and those volumes would come over to our pipes. So, you know, we are still expecting that. And Medallion, I think we have been able to jump into it pretty quickly by being able to bring our balance sheet to the fold to bring volumes onto our long-haul crude pipes and really just to enhance the gathering system by providing the full integrated service.

I think they are all on pace, with Magellan clearly leading the way just because we have been at it a little bit longer, and the opportunity set might be a little bit bigger given the overlap of our assets.

Jeremy Bryan Tonet: Got it. Understood. Maybe coming at it from a slightly different direction here, I think there was the expectation for the potential for EBITDA to approach $9,000,000,000 going into next year. And just wondering, I guess, beyond lower commodity prices, are there any other kind of drivers to the delta with the current outlook?

Pierce H. Norton: No, I think that the difference in our outlook has been really more—it is twofold. It is producer activity. You know, we clearly saw 100,000,000 a day of lower volume than we had expected in 2025. So, you know, we have not 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 is pretty much as simple as that. Volumetrically, our expectations are down a little bit.

We still see the building blocks that we have ready to come in here in 2026 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 have got some nice adds throughout 2026 that will give us some strength as we roll into 2027 regardless of what the commodity environment is.

Jeremy Bryan Tonet: Got it. Understood. Thank you.

Operator: Thank you. We will move next to Jean Ann Salisbury with Bank of America. Your line is now open.

Jean Ann Salisbury: Hi, good morning. 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, you know, given growing gas-to-oil ratio, we would expect, you know, 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?

Sheridan C. Swords: Yeah. I think if we think about that, I will just start with the clock and walk through it a little bit. It is obviously in the Bakken. We have talked about it for a period of time. We have a contract coming off this year where we are going to lose about 18,000 barrels a day going over to the Kinder Morgan system. So still going to see growth in that, but that is going to temper that down a little bit. In the Mid-Continent, it is an ethane story where 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 bringing some discretionary ethane on in that portion, and that is not predicted in these numbers as we 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 is kind of a little bit of—in a nutshell, it is 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.

We have not predicted to be at that same level this year.

Jean Ann Salisbury: Okay. That is very clear. Thank you. And then I kind of just wanted to follow up on Michael's question. So, you know, the Waha–Katy spread is still pretty wide for 2026, but it seems like maybe you did not put all of that into the guidance. But I guess my question is just, like, in 2027 when all those pipelines come on and that spread basically disappears, would we expect, like, basically a further material step down in that bucket in 2027?

Sheridan C. Swords: Well, what I would say is we contracted for that space on Eiger to be able to provide a service to our customers that we are bringing through our G&P processing plants to give them an outlet for their gas to continue to go forward. And we market that gas for them, 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 2027, we are predicting that volume will be used for our G&P business and natural gas that is coming off our plants to serve our customers.

Jean Ann Salisbury: Okay. That makes sense. Thank you.

Operator: Thank you. And we will move next to Julien Dumoulin-Smith with Jefferies. Your line is now open.

Rob Mosca: Hi. This is Rob Mosca on for Julien. Good morning, everyone. 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 would expect your Bakken G&P position to grow 1%? And maybe if not, what other factors could alter that correlation?

Sheridan C. Swords: Well, I think we have come out and said that it is 55% to—what our prediction is going forward. And, yeah, at this crude level, we are seeing a low single- to 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 are operating within cash flow today—and 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, very large position in there right now, so it is really about growth across the whole basin as we continue to go forth. So we really see it as, to get beyond that 1%, it 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 inventory around with more refracking and reworking older wells that can bring more volume on as well.

So as we look into the future, we think there are some other factors that could tend to push the tier two and tier three acreage into more economical areas that could be drilled at a lower price environment.

Rob Mosca: Got it. That is really helpful, Sheridan. And for my follow-up, I am wondering if you could provide an update on how you are 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 are adding more plants, and you have a pretty modest-sized NGL package rolling to you in 2027?

Sheridan C. Swords: I will 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 loop that system—we finally have to loop the whole thing—now we are sitting at well over 740,000 barrels a day on the system. As to the question about being able to attract third party onto our system, there are still G&P operators out there that are not associated with an NGL pipeline that are looking to move on an NGL pipeline.

There are RFPs out there today, as well as there are a lot of producers out there that have taken hybrids at existing plants that we are able to contract for that we are already connected to or can be connected to. So even though those plants may be owned by somebody that is associated with a long-haul NGL pipeline, we have been able to execute on both of those, and we see opportunities going forward not only in 2026, 2027, 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 frac capacity we will have at Medford, we think we compete for those very well.

Rob Mosca: Understood. Thanks for the time, everyone.

Operator: Thank you. And we will go next to Manav Gupta with UBS. Your line is now open.

Manav Gupta: 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 are seeing most of these opportunities? And also, are these opportunities tied to data centers, or is it a combination of data centers and LNG export projects? If you could talk a little bit about natural gas storage opportunities.

Sheridan C. Swords: Yeah. What I would say is I will kind of break our natural gas storage opportunities into two areas. One, the first area is Texas and Oklahoma, more on the legacy ONEOK, Inc. system, and that has mainly been driven by utilities going in there. We have expanded those a couple different times. We see opportunities to be able to expand them more. We continue to see if there are 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 completing out the GIST expansion that will go from, I think, it is 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 is another opportunity to grow the—to expand the GIST storage some more, and then there is the Bull and Mill storage over there. We think that there is an opportunity to grow as well. We have teams—engineering teams and geology teams—looking at that to see what we can do as we go forward. Those are going to be more driven by industrial customers and LNG people that are going to need those systems, of which we have had a lot of inquiry and natural gas into that.

So we do see a lot of upside on the storage beyond 2026 and beyond.

Manav Gupta: Thank you. 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 know, we have seen massive colds, 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 year-to-date? If you could talk a little bit about that.

Sheridan C. Swords: What I would say is so far through the year—I mean, you have to be careful; it can be cyclical 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 out to El Paso, which is very, very encouraging. Now, we have to be careful. A lot of times demand swings will change based on refinery turnarounds and what is going on in the system. But so far, we have 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.

Manav Gupta: Thank you so much.

Operator: Please go ahead. Thank you. Our next question comes from John Mackay with Goldman Sachs. Your line is now open.

John Mackay: Hey, good morning. Thank you for the time. I wanted to touch on the 2026 CapEx guidance. Could 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 two years? And then on a related note, how you are thinking about kind of all-in return profiles for that capital wedge? Thanks.

Pierce H. Norton: Sure. Well, the projects are the ones that I think Randy mentioned that come here in 2026: the Denver pipeline expansion in 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. We have a couple rolling over into the first six months or so of 2027. And then our larger projects really have been completed, and we will be on to the more ordinary course—what we call routine growth—expanding and extending our system.

We have been out there and said that we spend about $600,000,000, give or take, on maintenance, about $1,000,000,000 routine growth every year, and then we manage to find, you know, $400,000,000 or $500,000,000 of other larger capital projects that our commercial team is always out looking for. And that backlog is building. But we do not expect any—we do not see any real large capital projects like a thousand-mile pipeline or something on the horizon at the moment. Clearly, one we have not mentioned there is our joint venture on the dock, which will wrap up as we go into 2028.

John Mackay: Alright. Appreciate that. Thank you. 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. Thanks.

Sheridan C. Swords: Well, when we think about G&P growth in the Permian, you know, with the growth that we are seeing now in 2026 is from mid- to high single digits, and that is based on contracts that we have today coming on board. We are also seeing plenty of RFPs out there come forward—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 are customers of ours in other basins as well. So we feel very good going forward.

The great customer feedback that we have had and what we have done so far—we have, as I told you last time, with the Shadowfax plant, the volume we are doing in the Delaware has given us a little bit of operating room to be able to grow with these producers. And that is 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 more about—we built a platform with the inorganic growth that we have done so far.

We are really concentrated 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 in front of us that will continue to fuel growth, concentrating on these RFPs that are in volume growth in 2027 and beyond.

John Mackay: Understood. Thank you.

Operator: Thank you. And we will now move to Brandon B. Bingham with Scotiabank. Your line is now open.

Brandon B. Bingham: Hi, good morning. Thanks for taking the questions here. Just looking at the $150,000,000 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?

Sheridan C. Swords: What I would tell you about is when we put that together, we were at a $55 to $60 price environment. What we typically see as we think about those headwinds is that on the spread business, as crude prices are higher, we typically are wider. On our commodity exposure, that is mainly in the G&P business, and we have a systematic program of hedging, and we only try to leave only about 25% open on our commodity exposures as we continue to go forward. So as we think about going forward, if we would see some improvement in crude prices from the $55 to $60 range, we will see upside into our spread part of the business.

Brandon B. Bingham: Okay. Thanks. And then maybe just one quick follow-up. Just have not heard much on the Texas JV with MPLX. Just curious if you have anything to share. What is kind of the latest and greatest there? I know you mentioned it is part of the budget for this year, but just any updates you can provide?

Sheridan C. Swords: Well, I mean, it is progressing. The build side of that is progressing as planned; very satisfied with how we are going on that. On the commercial side, we are continuing to advance the commercialization of that dock. We like where we are today. The momentum is strong where we are today. We continue to have a lot of customer interaction with that, a lot of interest moving forward with quite a few people on that and going forward. So we like where we are at.

And one thing I would add to that is that we have multiple touchpoints at different levels of MPLX in here, and I am very, very pleased with the communication that is going back and forth between the two companies. Excellent collaboration.

Operator: Okay. Great. Thank you.

Operator: Thank you. We will now move on to Keith T. Stanley with Wolfe Research. Your line is now open.

Keith T. Stanley: Hi, good morning. 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 3.5 times target roughly? Second one on 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?

Walter S. Hulse: Well, I think that it is important to recognize that our 3.5 times target is a self-imposed target. The agencies for our current credit rating would 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, you know, we may or may not be a little bit opportunistic if we see opportunities in the capital allocation side. But we are 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 is going to take a little bit longer than we originally expected. But we are on track, and, you know, we were aggressively reducing debt through 2025. We still have a pretty strong CapEx project backlog this year. So we will not be able to lean in too much into the debt reduction until we start to complete those. In 2027, you will see that incremental free cash flow really kick up.

Sheridan C. Swords: And on the bundled NGL rate in the Bakken, yes, that is increased ethane recovery. What you are seeing is we had a pretty good fourth quarter with ethane recovering in there. You know, we are still roughly in that $0.30-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 it is going to be in that $0.30-ish range.

Keith T. Stanley: Got it. Thank you.

Operator: And we will go next to Jason Gabelman with TD Cowen. Your line is now open.

Jason Gabelman: Yes. Most of my questions have been answered, but maybe I will just ask one more on the M&A front. And more related to the refined products and crude segment—given the success in the Magellan business and kind of your unique footprint there. You have been growing in a segment that most peers have a smaller footprint. So perhaps you are better positioned to consolidate that part of the value chain. Is there a desire to further grow the refined products and crude business inorganically?

Pierce H. Norton: So, Jason, this is Pierce. I was wondering when the M&A question would come up. Our focus continues to be on executing for the 2026 plan and beyond. And we do not see any really glaring holes in our portfolio right now. So we are really pleased with what we have got. We are 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 are going to continue to be intentional and disciplined in our approach to M&A. So if that is adding refined products and crude or adding different things, then we are going to look at those.

But we are going to be really intentional about what we are doing.

Jason Gabelman: Understood. Thanks.

Operator: Thank you. At this time, we have reached our allotted time for questions. I will now turn the call back to Megan Patterson.

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 will 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.

Operator: Thank you. This brings us to the end of today's meeting. We appreciate your time and participation. You may now disconnect.

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