Prepared remarks
Good morning, and welcome to ONEOK's Second Quarter 2026 Earnings Call. As a reminder, this call is being recorded. At this time, I would like to turn the conference over to Megan Patterson, Vice President, Investor Relations. Megan, please go ahead.
Thank you, Jess. Welcome to ONEOK's Second Quarter 2026 Earnings Call. We issued our earnings release and presentation after the markets closed yesterday, and those materials are available on our website. After our prepared remarks, management will be available to take your questions. Statements made during this call that might include ONEOK's expectations or predictions should be considered forward-looking statements and are covered by the safe harbor provision of the Securities Acts of 1933 and 1934. Actual results could differ materially from those projected in forward-looking statements. For a discussion of factors that could cause actual results to differ, please refer to our SEC filings. With that, I'll turn the call over to Pierce Norton, President and Chief Executive Officer.
Thank you, Megan. Good morning, everyone, and thank you for joining us today. Joining me on the call are Walter Hulse, our Chief Financial Officer; Randy Lentz, our Chief Operating Officer; and Sheridan Swords, our Chief Commercial Officer. Yesterday, we reported second quarter earnings and raised our 2026 financial guidance for the second time this year, reflecting strong year-to-date performance and continued momentum heading into the back half of the year. Our second quarter results were driven by record NGL throughput volumes, strong refined products demand and continued volume growth across our systems. The quarter highlighted the positioning of our asset footprint, the value of our integrated platform and the outstanding execution of our employees. The broader energy backdrop remains constructive, but the more important point for ONEOK is that we are converting that backdrop into visible growth.
Our footprint connects key supply basins with domestic and international demand across natural gas, natural gas liquids, crude oil and refined products. The connectivity across our business segments gives us multiple ways to grow earnings, optimize existing assets and allocate capital toward opportunities with attractive returns. Importantly, these opportunities are not confined to a single commodity or region. Our integrated system enables us to create value across multiple demand drivers, a differentiator for ONEOK. Our confidence is reflected in our long-term outlook. We continue to target mid- to high single-digit adjusted EBITDA growth over the next 5 to 7 years, supported by 3 factors that are increasingly visible. Recently completed and soon-to-be completed projects drive structural growth spanning Permian Basin processing capacity, Powder River processing capacity, Mid-Continent fractionation capacity, refined products expansions, and natural gas transportation and storage capacity, and LPG exports.
Operating leverage available across our assets, requiring little to no capital investment and allowing us to be flexible to customers' needs and timing. And finally, a growing pipeline of high-return organic projects, bolt-on acquisitions and commercial optimization are creating additional investment opportunities across our system, where commercial discussions are improving our confidence in timing, scale and returns. Our long-term strategy remains grounded in the same principles that have gotten us to where we are today, operational excellence, financial discipline and a value-driven approach to capital allocation. With that, I'll turn it over to Walter for a financial update. Walter?
Thank you, Pierce. As Pierce mentioned, our second quarter performance and strengthening outlook across our business supported a second increase to our 2026 financial expectations. We now expect a 2026 net income midpoint of $3.6 billion, a diluted earnings per share midpoint of $5.68 and an adjusted EBITDA midpoint of $8.35 billion. This represents net income and adjusted EBITDA increases of $150 million and $250 million, respectively, compared with our original guidance provided in February. At the segment level, Natural Gas Pipelines, and Refined Products and Crude continue to perform toward the upper end of the adjusted EBITDA ranges provided in our original guidance. Natural Gas Liquids, and Gathering and Processing remain well positioned through the balance of the year. Across the portfolio, organic volume growth, EBITDA from recently completed projects and attractive hedging and commercial opportunities are providing momentum in the second half of the year and into 2027.
Our 2026 capital expenditure guidance remains unchanged at $2.7 billion to $3.2 billion. We expect capital spending to accelerate through the second half of the year as several major projects move towards completion, bringing us towards the upper end of our CapEx guidance range. Turning to the second quarter results. ONEOK reported net income of $967 million or $1.53 per diluted share, a 13% increase year-over-year. Adjusted EBITDA totaled $2.12 billion, up 7%, driven by volume growth and strong segment level performance. We continue to expect earnings to largely follow the normal seasonal cadence of our business as we move through the remainder of 2026, with the tailwinds I just mentioned supporting second half results. Our overall financial position remains strong and continues to provide the flexibility to invest in the business, return capital to our shareholders and pursue opportunities that create long-term value.
As additional guidance on the application of the One Big Beautiful Bill and the Inflation Reduction Act has become available, we've continued to evaluate the impact of the tax legislation, particularly as it relates to acquisitions and bonus depreciation. Based on our latest analysis, we now expect approximately $2.6 billion of cumulative cash tax benefits compared with the approximately $1.5 billion we previously discussed. These additional benefits, combined with our existing tax attributes are expected to defer meaningful cash tax payments until 2031, extending our cash tax runway by approximately 2 years and further enhancing future free cash flow generation. Higher earnings and improved free cash flow also support continued progress towards our long-term leverage target of 3.5x debt to EBITDA. I'll now turn it over to Randy for an operational and large capital projects update.
Thank you, Walter. Our teams continue to execute at a high level throughout the second quarter while maintaining focus on safety, reliability and customer service. Performance across the system remains strong, supported by increasing customer activity, improving asset utilization and contributions from recently completed projects. As volumes grow across our footprint, we're seeing the benefits of the connectivity and scale of our assets. We continue to advance the project portfolio. And as of August 1, our Denver area refined products expansion was placed in service. This project adds 35,000 barrels per day of capacity into one of the fastest-growing markets in our footprint and provides a new direct jet fuel connection to Denver International Airport. In the Permian Basin, we continue to expand processing capacity to support growing producer activity. Following our recently relocated 150 million cubic feet per day plant in the Midland Basin, we remain on track to complete 110 million cubic feet per day of Delaware Basin plant expansion projects during the third quarter.
Additionally, based on production outlooks in the basin, we've increased the capacity of our Bighorn plant to 400 million cubic feet per day from an initial capacity of 300 million cubic feet per day. Bighorn remains on schedule for completion in mid-2027. Upon completion, our Permian processing capacity will increase to nearly 2.4 billion cubic feet per day. In addition, along with our initial 60 million cubic feet per day Cutter plant in the Powder River Basin, which was previously announced, we've begun construction on another 120 million cubic feet per day Cutter 2 plant, which we expect to be online in the first quarter of 2028. And finally, Phase 1 of our Medford fractionation project remains on track for completion during the fourth quarter. Medford Phase 1 will add 100,000 barrels per day of Mid-Continent fractionation capacity with Phase 2 expected to be completed in the first quarter of 2027.
Looking ahead, the projects entering service over the next several quarters are expected to add visible earnings, increase system utilization and support our long-term growth outlook. With that, I'll turn the call over to Sheridan for a commercial update.
Thank you, Randy. Commercial activity remained strong during the quarter, supported by favorable fundamentals across all four of our business segments. We delivered solid volume growth across our integrated system, driven by increased customer activity, healthy domestic and international demand, and continued production growth in key producing basins. Starting with the natural gas liquids segment, raw feed throughput volumes increased 7% year-over-year with growth across all regions. Utilization continued to increase across the system, supported by Permian region-led plants. In the Rocky Mountain region, NGL volumes increased year-over-year, even taking into account a contract roll effective at the beginning of the quarter, which was previously discussed and assumed in guidance. This was more than offset by growth across the region and continued strength in ethane recovery. Higher NGL pricing and export demand continue to support ethane recovery across all regions, and we expect these dynamics to remain favorable into the third quarter.
Global NGL demand remains strong, supported by growing petrochemical demand and continued interest in securing long-term access to reliable U.S. supply. We're pleased to announce that we've reached our targeted contracting threshold of 80% for our 200,000 barrels per day of LPG export capacity, which is currently under construction as part of our export dock joint venture. The capacity is supported by high-quality counterparties and customer interest remains robust, including discussions that extend beyond the initial contracted period and into the next decade. This underscores both the growing demand for U.S.-sourced LPGs and the value of the terminal's advantaged locations. Turning to the Refined Product and Crude segment, demand fundamentals remained positive during the quarter. Year-over-year refined products volumes shipped increased 8%, supported by gasoline and diesel demand, high refinery utilization and refinery maintenance dynamics.
Blended volumes were also strong during the quarter, driven by increased system throughput. Higher gasoline volumes allow us to blend more product and further optimize operations across our network. While our hedge position limited our ability to fully capture the benefit of wider spring blending spreads, we have secured additional fall hedges at higher prices and extended new hedges into spring 2027, improving visibility into future blending margins. The location and flexibility of our refined product system and our ability to clear barrels in a dynamic market remains significant competitive advantages. As refinery utilization remained high and product flows continue to evolve, our unique bidirectional connectivity between the Mid-Continent and Gulf Coast allow us to efficiently connect supply with the strongest demand markets, including an increasing pull for U.S. refined products and exports along the Gulf Coast.
Demand for our marine export services also remained robust. At our Seabrook crude export joint venture, throughput increased approximately 20% compared with the first quarter, including record crude oil loadings in May. The facility remains highly contracted and under take-or-pay agreements for the foreseeable future. Midland crude gathering volumes increased 10% compared with the first quarter, reflecting continued strength in this higher-margin business. Rigs have steadily increased on our Midland crude gathering position throughout the quarter, and we currently have more than 30 rigs operating on our acreage. In addition, strong Houston-area refining and export demand drove outperformance on our long-haul crude oil pipelines. Moving to the Natural Gas Gathering and Processing segment, volumes increased across all regions compared with both the second quarter of last year and the first quarter of this year.
Producer activity remains healthy across our footprint, and development plans continue to track largely in line with expectations communicated throughout the year. We maintain good visibility to the remainder of 2026 and into 2027. In the Permian Basin, our recently added Midland capacity expansion positions us well to support increased development activity in the Barnett formation, while our planned projects in the Delaware Basin provide additional capacity to support anticipated growth into 2027 and beyond. We currently have 11 rigs on our acreage in the Mid-Continent and 13 in the Rocky Mountain region, up 2 rigs in the Rockies compared with last quarter. Both areas experienced a seasonal pickup in activity during the second quarter, driven by higher well completions. I'll close with our Natural Gas Pipelines segment, where continued transportation demand and favorable market conditions drove another strong quarter.
Waha Hub to Katy location price differentials continue to benefit this segment during the second quarter. We expect lower earnings in the second half of the year as Permian takeaway capacity enters service and differentials narrow, consistent with our full year outlook and guidance assumptions. Looking forward, power generation, LNG exports and industrial development continue to support increasing natural gas demand across our footprint. We continue to advance commercial discussions supporting multi large-scale data center developments. While these projects have not yet reached FID, continued commercial activity reinforces our confidence in the scale and durability of the opportunity. From a power generation perspective, we were recently awarded a supply agreement for 1 gigawatt of power plant demand, further expanding our participation in a growing source of natural gas demand. Supporting electric generation has long been a core part of our business.
Our intrastate natural gas pipeline system is already directly connected with numerous power plants across our footprint and is well positioned to serve future demand growth. Pierce, that concludes my remarks.
Thank you, Sheridan, Randy and Walter. As we step back, it's clear that demand fundamentals remain strong and the long-term outlook for U.S. energy infrastructure remains compelling. And as we look across our business, the message is straightforward. We raised guidance for the second time this year, extended our cash tax runway, advanced key projects and strengthened visibility into earnings growth and free cash flow through 2027. Our integrated multi-molecule platform positions us to capture opportunities across commodities, regions and demand drivers while maintaining financial and disciplined flexibility. And most importantly, none of this would be possible without the dedication of our employees and their commitment to safe, reliable and disciplined execution. With that, operator, we're ready to take questions.
Questions and answers
Our first question comes from Spiro Dounis with Citi.
I want to start on the growth strategy from here. Pierce, I think you had talked about aspiring to grow mid- to high single digits over the next few years and curious just to get more color on that front. Specifically, how much of that growth can be underwritten by filling up the white space that you mentioned on the current system versus building out new infrastructure. You mentioned a growing backlog of projects coming. So how should we think about maybe the timing of when those projects could come to market? And maybe which verticals you see probably getting the most attention?
Spiro, I'd start out by saying that it's not one thing that's driving this conclusion for us. We actually have multi-reinforcing growth drivers. Our assets are positioned in these premier growth basins in the U.S. and especially in our export markets. And the growth across our footprint is actually underpinned by basically five things, not just filling the white space that you mentioned. It's the continued strong Permian, Mid-Continent and Powder River growth and the associated natural gas liquids. It's the stable Bakken growth through improved well productivity. It's the rising U.S. LPG export market, and there's a shift definitely in the global crude oil demand to a more reliable and a more resilient supply. And then you've got LNG exports that's driving the natural gas increase across the United States that's driven by that growing 30 Bcf a day or over 30 Bcf a day LNG export and your domestic natural gas-fired generation and industrial demand. So these facts all give us the confidence to that high single-digit EBITDA growth over the next 5 to 7 years. So it's not just one thing, it's a multitude of things, and it's across all five of our business segments.
Got it. Second question, maybe for you, Sheridan, just zeroing in here on the NGL segment. Looking for more color on the dynamics around the quarter. Volumes were really strong, as you pointed out, but margins may be a little bit softer overall. Can you talk about some of the dynamics that were driving that this quarter and how you're thinking about margins going to the back half of the year? Should they stay at these levels? Do you think there's a reason to think we could see expansion?
As we talk about the margins, we did see a little reduction in the overall margin on certain parts of our system. This was really driven by increased ethane we saw versus how much the increase in C3+ we had. That happened in all three regions: Permian, Mid-Continent and the Bakken, where discretionary ethane out of the Bakken is at a much lower rate than what the C3+ at full rate is getting out of the Bakken. We did see increases in C3+ in the Bakken, but we also saw a greater increase in ethane. That also became apparent in the Mid-Continent, where we had a large increase in ethane. Those rates are tiered rates we've had for a period of time where we charge a higher treatment and fractionation rate for the C3+ than we charge for ethane even at full rates. So as more ethane comes on, it can have a slight effect on our overall margins. But we are seeing a lot of increased volume across our system. One area to note is the Permian on volume where in the last month or two we've seen a strong, substantial increase in volumes. That increase was tied to the Waha to Katy spread. As that spread became positive, we saw a lot more volume than we had anticipated behind our NGL system in that area. July has been a strong month and August is following suit with a good uptick in volume on our NGL system.
We'll go next to Jean Ann Salisbury with Bank of America.
There's been some talk from some E&Ps year-to-date around reducing their midstream costs. In that context, can you update us on the duration of your NGL T&F contracts out of the Bakken?
Yes. Our rates out of the Bakken are still extended for a period of time. We really don't have anything of material coming up until late this decade, and most of the contracts extend into the next decade. So we feel very good about our NGL rates out of the Bakken at this time.
And refined product prices in PADD 4 have continued to rise year-to-date versus PADD 2. I believe you've said before that your Denver pipeline is mostly long-term contracted, but is there a meaningful exposure to the spread at these price levels?
No, the 35,000 barrels per day is signed up by firm take-or-pay contracts. There may be a small opportunity our operating team finds to capture incremental spread, but the majority, almost all of it, is under long-term firm contracts.
We'll go next to Jeremy Tonet with JPMorgan.
This is Robert Kad on for Jeremy. There's potential for additional egress out of the Bakken. I was curious if you could speak to your outlook for ethane recovery at this point, maybe ONEOK's positioning against that backdrop?
Yes. Our egress for NGLs out of the Bakken is strong. We still run up around sometimes up to 500,000 barrels a day, which gives us plenty of capacity to move volumes. We can flex on ethane if we want to. So we don't really see NGL egress out of the Bakken being an issue in our forward plan.
Got it. And as a follow-up, I want to dive deeper on the Mid-Continent. It looks like decent producer activity within the region. There might be a contract roll next year, but curious if you could dive a little bit deeper into your outlook for the balance of '26 into '27?
Yes. We continue to have contracts that roll in the Mid-Continent in different areas, and some of them were put on at higher times where margins were higher. So there could be some of these contracts coming back to more of what we see the market is at this time. But typically, when dealing with customers, there's a give and take in areas that we work with, and value shifts back and forth between different basins as we bundle rates with our large contractors. Most of our contracts in the Mid-Continent still have some term on them for a period of time; nothing is coming up in the next month or two or even into next year.
The only thing I'd add to that is the fact that any sort of contractual movement, we've already factored that into our guidance number. So that's fully baked in at the market rates.
We'll go next to Praneeth Satish with Wells Fargo.
I guess just turning to the Permian. So obviously, you're seeing good growth there, strong demand. When we think about West Texas LPG specifically, how much remaining uncontracted capacity do you have on the system? And how much more room do you have there to support the growth that you're seeing in the Permian? And then maybe just sticking on Permian NGLs. If I remember correctly, with some of the legacy EnLink volumes, they're moving on relatively higher cost NGL transportation paths. And so as those contracts roll over, to what extent can those be migrated to West Texas LPG? And what's kind of the time frame for that?
On your first question, with the expansion of the West Texas NGL mainline, we have capacity up to 740,000 barrels a day. With that and what we're seeing today, we still have plenty of capacity to meet demand coming on from our processing plant expansions, growth from third-party plants, and potential future processing growth we have not yet announced. We think we have a very good position there with a lot of operating leverage and can move additional NGLs on that system. We don't see needing to expand that system for a period of time. Regarding the legacy EnLink volumes, there's a little over 50,000 barrels a day that we control that were previously contracted under EnLink on another third-party pipeline. Those contracts will start rolling off starting later in 2026 and into 2027 and 2028, and that volume will come directly over to our NGL pipeline when they roll off.
Okay. Great. And then maybe going back to, I think it was Jeremy's question, but I think you kind of took it as NGL egress. But I think his question and mine is there are a few proposed gas takeaway projects being proposed in the Bakken and it seems like at least one of them may move forward, sizable projects. So I guess the question is if gas egress improves in the Bakken, how does that impact your outlook for basin growth, BTU levels and really ethane recovery? And could you see more upside from potential more production growth offsetting maybe some downside from lower ethane recovery? Just how do you think about that?
Any time producers get better netbacks, it helps incentivize increased production. For our discretionary ethane out of the Bakken, a lot depends on what is coming out of Canada and how much is held back. That incremental Mcf from Canada is still a factor for the system. We still think the ethane side will be a nice optionality for us on the discretionary side as we move forward.
We'll go next to John Mackay with Goldman Sachs.
I want to go back to some of the questions around the longer-term growth outlook. Pierce, I appreciate the different drivers you called out there. Just curious if you could touch a little bit more on kind of the incremental growth spending, where projects could fit in there? And what do you think a run rate growth CapEx budget could be like to support that outlook?
I appreciate the question. I'll turn that to Walter for the capital spending update.
As we've been talking about, we have a pretty nice backlog that is building. We've got quite a bit being completed here in 2026 and 2027, all of which will then bring on that EBITDA going forward. The backlog we have is more in the midsized projects. We don't have any $1 billion plus projects on the horizon right now. That should moderate our CapEx from the current levels down into that $2 billion to $2.5 billion kind of run rate going forward. Of course, our commercial team is always out there looking for great opportunities. To the extent we find them, we'll clearly jump on them. But with that $2.5 billion run rate, you're going to see some very significant free cash flow coming to the bottom line.
I appreciate that. And maybe just a follow-up for me. You've talked a couple of times in recent calls around some of these gas laterals to feed BTM or broader power generation. Could you talk a little about what the commercialization process has been like so far? And tying it into your last comment about the run rate of growth CapEx, how much of that could be going towards this vertical?
I'll take the first part on AI data centers and power generation. As I mentioned in my prepared remarks, we secured a 1 gigawatt power generation supply contract. It's a strong project and not a high-capital project—over $100 million of capital with a very attractive return and firm demand. We are also in late stages of discussions with a couple of other opportunities to supply AI data centers. Commercialization has taken a bit longer than anticipated for some of these projects, which we've seen more broadly across the industry. But we're feeling good about our position and our competitive advantages have helped advance these discussions.
On the capital side, those types of projects are what I was referring to. They're singles and doubles—typically $100 million to maybe $400 million, $500 million at the top end. They fit nicely into our capital budget going forward. Randy also discussed other projects underway, many of which are attractive doubles and triples in size.
We'll go next to Theresa Chen with Barclays.
Given the growing global focus on energy security and reliable supply, you noted increasing commercial traction for the LPG export facility. How do you see the opportunity set for exports broadly evolving from here, both in terms of the LPG export project as well as brownfield expansion opportunities and/or recontracting upside on your existing liquids export infrastructure?
We are very satisfied and excited about reaching our threshold on the LPG export dock. As noted, we have discussions with potential offtakers about securing supply when the initial contracts roll off into the next decade. Since the war, we've seen many new entrants wanting the security of U.S. supply for both LPG and crude oil. Our Seabrook export dock is 100% contracted into the foreseeable future under firm take-or-pay contracts. We are seeing growth across liquids demand, including refined products export capacity. We are seeing strong pulls on refined product exports, which pull volume throughout our system. We want to get the LPG terminal up and operating and demonstrate operational reliability to customers. We will continue to look for other opportunities and engage customers. There is a clear resurgence of interest in secure U.S. energy supply.
Some of the upside could be in the remaining 20% of capacity, where producers and customers may want full wellhead-to-water pull. Leaving that position available creates potential upside for us beyond the initial contracting, in addition to operational considerations.
With the Denver refined products pipeline expansion now in service and commentary from the downstream community about moving additional volumes from PADD 4 into PADD 5 over time, how has your view of PADD 4 regional supply and demand balance evolved for the Denver area and beyond? As PADD 4 becomes tighter, what opportunities does this create across your infrastructure footprint for Mid-Con to Rockies movement? And how are you thinking about potential for further expansion on that Denver pipeline system beyond the jet fuel movement?
We're excited to have the Denver pipeline up and operating. Operations did a great job getting it on time. We installed a 16-inch pipeline that could have upwards of possibly 200,000 barrels a day of capacity, and we're currently running 35,000 barrels a day on it. We've seen for some time that PADD 4 could need more volume going forward, and this pipeline can supply that. There has been talk of projects into Salt Lake City where we expect to play a role; we can get capacity there quickly and cheaply because we've set the pipeline up for expansions going forward. Getting this pipeline was critical to demonstrate our ability to expand and supply growing demand in PADD 4.
We will go next to Keith Stanley with Wolfe Research.
First, I wanted to clarify on the mid- to high single-digit EBITDA growth. Walter, it sounds like you're saying that's tied to $2 billion to $2.5 billion a year of CapEx. Any color you can give on what that assumes for volume growth and if that includes or does not include any bolt-on M&A of any kind?
It's really a combination of future CapEx and filling the white space; we have plenty of operating leverage across our businesses. As we execute brownfield expansions off of that, we'll continue to capture opportunities at attractive capital levels. Near-term drivers include the world seeking diversity of supply, significant volume growth on our refined products going to the Gulf Coast, rigs up in every basin with visibility to more coming, and commodities being well-hedged in 2026. We benefited from the Waha to Katy spread, which brought NGLs from third-party plants on to our system. With this constructive backdrop, we're confident in the new guidance and, if momentum holds, we might update you again in Q3.
Great. Second one on ethane recovery. Is there any way to quantify how much incremental ethane recovery you saw with the market dynamics in Q2, particularly in the Bakken and Mid-Continent? It seems like a meaningful boost to volumes based on the change in rate.
We saw a significant increase in ethane recovery in the Mid-Continent, which is one of the largest increases. We also saw an increase in the Bakken, though the difference in rates between full-rate C3+ and discretionary ethane means a little bit of additional ethane can affect overall margins modestly—on the order of a penny or so. So we saw good ethane recovery in the Bakken and some in the Permian as well, although Permian growth was more weighted to the C3+ side.
We'll go next to Sunil Sibal with Seaport Global Securities.
In your prepared remarks, you talked about upsizing some previously announced projects. Is that a result of more customers coming in or existing customers increasing their demand for processing capacity?
We have a bit of both. Existing customers are performing and expanding, and our commercial team is doing a strong job securing additional deals and interest from customers to increase capacity. So it's a mix of increased customer activity and expansion of commitments.
Okay. And then with the mid- to high single-digit EBITDA growth that you guys outlined, how does that translate into the EPS growth rate? It seems like capital spend will be fairly capped at organic projects. Could you clarify?
We would expect EPS growth to exceed EBITDA growth, especially as we move into more free cash flow and potentially opportunistic buybacks. We're constructive on EPS growth.
We'll go next to Manav Gupta with UBS.
Could we get an update on your Permian processing plants that are set to come online in the near future?
In the Permian, as Randy outlined, we have 110 million cubic feet per day coming online in the third quarter in the Delaware, and that will fill quickly—we have good line of sight on volume growth in that area. The Shadowfax plant in the Midland is already up and running and will fill quickly. We have the Bronco plant coming later into 2027 in the Delaware, and that will fill as well. We upsized the Bronco project from 300 million to 400 million cubic feet per day, which improves the project's returns.
Perfect. I just want to go back quickly to the 2026 guide. Help us understand what could drive further guidance revisions that you kind of hinted at and what could put you towards the top end of that guide of $8.5 billion?
A pickup in producer activity, continued constructive refined product spreads, rigs across the board coming online, and strength in our crude gathering business with more rigs are examples of drivers. We're seeing customers position for higher prices and growth through 2026 and into 2027. Those factors could push us further toward the top end of guidance.
One additional point: we came into 2026 pretty hedged on refined products, but with increased volume across our system we can hedge more or blend more on incremental volumes at higher realized prices. If this incremental strong volume continues into the later half of the year, that provides additional tailwinds.
We'll go next to Julien Dumoulin-Smith with Jefferies.
This is Alex Omer on for Julien. Just a quick question and a point of clarification. How much of the mid- to high single-digit is predicated on those bolt-on acquisitions that you talked about? And where are you seeing the best opportunities for bolt-on M&A across your footprint?
The majority of that growth is organic—we expect to optimize systems, fill white space with little capital, and pursue brownfield opportunities. We'll be intentional and disciplined on M&A, expanding and extending our footprint where attraction and returns make sense. We'll look wherever those opportunities present themselves.
Got it. For that mid- to high single digit, what is the implied Bakken volume growth underpinning that? Is it similar to what you talked about at the beginning of the year—low single-digit kind of growth?
Yes. That's right. We're staying with the low single-digit assumption for Bakken growth.
We'll go next to Gabe Daoud with Truist Securities.
I wanted to go back to the volume side. You mentioned in the Permian seeing incremental gas show up as the Waha to Katy spread significantly improved. Have you quantified that number? I'm trying to think how you, at least in the Permian, could land at the high end of your volume guide of 1.7 Bcf.
We've seen the largest NGL pickup coming from third-party plants, and we've seen some pickup on the gathering and processing side. At times, incremental volumes have approached as much as 100,000 barrels a day.
Got it. On the NGL side. Okay. That's helpful. As a follow-up, on the mid single-digit EBITDA growth number, if rigs on your system today carry through to 2027, does that get you there on growth from a volume standpoint? Or do you also expect rigs to continue to be added as we progress through 2026 into 2027?
In some areas there will be additional rigs. We've talked to producers about adding more rigs. For example, we expect another rig to be added in the Bakken. So it's based on current rig counts and discussions with producers about future additions.
We pay close attention to rig counts related to gas and associated gas. We are also seeing significant activity on our dedicated oil gathering positions, which is meaningful and part of the reason we included that in our prepared remarks.
Yes. That's helpful. Thanks for the color.
We will take our final question from Jason Gabelman with TD Cowen.
I wanted to go back to the Permian and ask about your processing growth. It seems like some competitors are sanctioning plants beyond 2027 and into 2028 and 2029. How do you feel about your processing growth potential beyond 2027, given things like needing to lock in equipment and labor? Do you need to FID projects now to make sure they come online to support continued growth beyond 2027?
We upsized Bighorn as we expected and were able to take advantage of that with a relatively low incremental capital increase. We've also secured long-lead equipment and effectively have another plant secured that we can deploy into the Permian as needed. With the growth we're seeing from existing customers and their plans, we stay ahead of the need to perform, and that's what we've done.
That concludes our question-and-answer session. I would now like to turn the call back over to Megan Patterson for closing remarks.
Thank you, Jess. Our quiet period for the third quarter starts when we close our books in early October and extends until we release earnings in late October. We'll provide details for that conference call at a later date. Our IR team will be available throughout the day for any follow-ups. Thank you for joining us, and have a great day.
Thank you. That concludes today's call. You may now disconnect your lines at this time, and have a wonderful day.