Kinetik Holdings Inc. (NASDAQ:KNTK) Q3 2025 Earnings Call Transcript

Kinetik Holdings Inc. (NASDAQ:KNTK) Q3 2025 Earnings Call Transcript November 7, 2025

Operator: Good morning, and thank you for attending the Kinetik Third Quarter 2025 Results Call. My name is Elissa, and I will be your moderator today. [Operator Instructions] I would now like to pass the call to your host, Alex Durkee, Investor Relations. Please go ahead.

Alex Durkee: Thank you. Good morning, and welcome to Kinetik’s Third Quarter 2025 Earnings Conference Call. Our speakers today are Jamie Welch, President and Chief Executive Officer, and Trevor Howard, Senior Vice President and Chief Financial Officer. Other members of our senior management team are also inattendance for this morning’s call. The press release we issued yesterday, the slide presentation, and access to the webcast for today’s call are available at www.kinetiks.com. Before we begin, I would like to remind all listeners that our remarks, including the question-and-answer section, will provide forward-looking statements, and actual results could differ from what is described in these statements. These statements are not guarantees of future performance and involve a number of risks and assumptions.

We may also provide certain performance measures that do not conform to U.S. GAAP. We’ve provided schedules that reconcile these non-GAAP measures as part of our earnings press release. After our prepared remarks, we’ll open the call to Q&A. With that, I’ll turn the call over to Jamie.

Jamie Welch: Thank you, Alex. Good morning, everyone. We appreciate you joining us today. Kinetiks’ third quarter results reflect a combination of strong execution across key strategic initiatives and the realities of a challenging commodity price environment, particularly in September. While we exited the quarter in line with our operational expectations, the path to get there was not without its complexities. Through it all, our team remained focused and disciplined, executing on what we can control and continuing to advance our long-term strategy. I’ll begin with an update on our strategic initiatives, and then I’ll turn it over to Trevor to walk through our financial results and guidance updates in more detail. Starting with our strategic projects, I am incredibly proud of our team’s work to bring Kings Landing to full commercial service in September, adding organic processing capacity in New Mexico.

The start-up of Kings Landing presented as we navigated taking over the project post design, engineering, and procurement preconstruction. And our team worked tirelessly to keep the project on track. We now have a well-constructed plant at a site that will allow for processing capacity expansions with much fewer challenges to contend with. Kings Landing represents a significant step for our Delaware North customers. Even with Waha natural gas price-related shut-ins and a slower return of previously curtailed volumes, we are consistently flowing over 100 million cubic feet per day, which is in line with our original expectations. Over the remainder of the year, we will continue to perform gathering system modifications to segregate sweet gas and direct it to Kings Landing while keeping the sour gas flowing to Dagger Draw and Maljamar.

We look forward to the return of shut-in PDP and bringing on the remaining curtailed volumes. We also look forward to enabling our customers to resume development of new wells after more than 2 years of curtailments and minimal activity. We also made quite a bit of construction progress on the ECCC pipeline that connects our Delaware North to our Delaware South system. We expect ECCC to be in service during the second quarter of 2026. Beyond the projects currently underway, we have reached FID on the acid gas injection project at King’s Landing. We expect to receive the project’s permit from New Mexico regulators before year-end 2025, and the project has an expected in-service of late 2026. This will enable Kinetik to take high levels of H2S and CO2 gas at all of our Delaware North processing complexes, and meaningfully increase our total asset gas capacity.

From conversations with many of our producer customers in New Mexico, we knew that we needed to build confidence in our service offering and capabilities. Bringing King’s Landing online was a huge first step. The conversations have now shifted to centering on additional processing capacity and sour gas treating capabilities to support future development plans that optimize capital deployment and drilling efficiency for producers, allowing them to drill multiple benches at once, which also eliminates potential parent-child well challenges. We’re meaningfully advancing those discussions, and we believe that the ATI project will strengthen our competitive position and enable us to soon announce the processing capacity expansion at King’s Landing.

Kinetik is well-positioned to capitalize on the growing power generation opportunity in the Permian Basin and is actively pursuing innovative, scalable solutions to participate meaningfully in this evolving energy landscape. We’re excited to announce a new opportunity that further demonstrates our ability to unlock value through strategic partnerships. Kinetik finalized an agreement with Competitive Power Ventures, or CPV, to connect our owned and operated residue gas pipeline network to the 1,350-megawatt CPV Basin Ranch Energy Center in Ward County, Texas, which will be used as one of the primary sources of supply for the plant. This connection will be made at no capital cost to Kinetik, creating another highly efficient and accretive pipeline outlet for our residue gas.

This arrangement also supports new large-scale in-basin power generation to meet growing electricity demand in the region. Importantly, this project serves as a blueprint for future collaborations. It showcases how we can leverage our infrastructure and relationships to create scalable capital-light solutions that support our long-term value proposition. As part of our broader strategy to enhance market access and deliver value to our customers, we have made significant progress in continuing to support Permian residue gas takeaway. We executed a 5-year European LNG pricing agreement with INEOS at Port Arthur LNG beginning in early 2027. Under this agreement, we will deliver residue gas at a designated interconnect on the Permian Highway pipeline, representing the MMBtu equivalent of approximately 0.5 million tons per annum.

The gas will be priced monthly based on the European TTF index, providing our customers with diversified exposure to international pricing. This agreement underscores our differentiated service offering and commitment to delivering innovative and value-added solutions in the Permian Basin. Additionally, we’ve expanded our takeaway capabilities by securing additional firm transport capacity to the U.S. Gulf Coast commencing in 2028. This incremental capacity will significantly enhance our customers’ access to premium markets and reflects our continued efforts to address critical takeaway constraints at the Waha Hub. Together, these commercial arrangements strengthen our ability to support producer growth, improve premium pricing optionality, and reinforce our position as a reliable and best-in-class midstream partner.

Before I turn over the call to Trevor, I’d like to touch on our financial performance versus expectations for the past 4 quarters. For almost 3 years, this management team has done a very good job of being able to execute our strategy, fill our residual cryo processing space with new dedications and commitments, and beat and outperform our financial expectations and guidance. Over the past 4 quarters, we have stumbled, and we recognize that we need to do better. We have had some challenges as we’ve integrated the Delaware North system into our business, such as the delays for King’s Landing to reach service. Meanwhile, we’ve endured challenging and turbulent macro commodity and inflationary headwinds this year. These are not excuses. These are just facts.

The buck stops with us. And as the largest individual owner of this company who has never sold 1 share, we will absolutely do better, and I will not rest until we do. We are forensically analyzing and improving our forecasting assumptions, including evaluating the use of AI tools and machine learning to do so. We will challenge ourselves on direct and indirect risks and how to mitigate them. And we will aggressively reduce our controllable costs in all segments. Our reputations and credibility are in question, and we will respond with relentless grit, purpose, and resolve to address and rectify the situation. Looking ahead, we’re executing on a robust multiyear organic investment strategy that positions Kinetik for long-term success from advancing strategic infrastructure projects like Kings Landing and the ECCC pipeline to developing scalable solutions in sour gas treating and gas supply for large-scale new market-based power generation in Texas.

Our focus remains on delivering differentiated services and unlocking value across our footprint. These efforts, combined with our commitment to disciplined execution and enhanced forecasting, reinforce our long-term value proposition and our role as a trusted partner in the Permian Basin. Now I’ll turn the call over to Trevor to discuss third-quarter results in more detail and our outlook for the remainder of the year.

Trevor Howard: Thanks, Jamie. In the third quarter, we reported adjusted EBITDA of $243 million. We generated a distributable cash flow of $158 million, and free cash flow was $51 million. Looking at our segment results, our Midstream Logistics segment generated an adjusted EBITDA of $151 million in the quarter, down 13% year-over-year. The decrease was largely driven by lower commodity prices, lower Kinetik marketing contributions, higher cost of goods sold, and higher operating expenses, partially offset by increased volumes across both our Delaware North and South assets. Shifting to our Pipeline Transportation segment, we generated an adjusted EBITDA of $95 million. Total capital expenditures for the quarter were $154 million.

As we disclosed in our earnings release yesterday, volume-related headwinds combined with producer-directed actions from commodity price volatility, the timing of the Kings Landing start-up, and the EPIC crude sale closing have led us to update our full-year adjusted EBITDA guidance range to $965 million to $1.005 billion. I will walk through several key factors behind our revised expectations. First, as Jamie discussed earlier, the timing to reach full commercial in service at Kings Landing was slower than anticipated in September. While we exited the quarter at our expected operational run rate, the timing and the pace of those volume contributions and the associated margin fell short of our initial expectations. The delay in bringing King’s Landing fully online versus our original assumption of July 1 reduced full-year earnings by approximately $20 million.

Second, we’ve continued to navigate sustained commodity price volatility and macroeconomic uncertainty throughout much of 2025. Our updated outlook now reflects market forward pricing as of October 31, which represents over a 2% decline from the commodity strip used to revise guidance in August and a 12% decline versus our original assumptions in February. Notably, Waha natural gas pricing, which is not included in the figures I just stated, has declined by over 50% since our February assumptions. Together, this has negatively impacted full-year adjusted EBITDA expectations by nearly $30 million versus our original guidance, excluding Gulf Coast marketing impacts. These lower average commodity prices have had both direct and indirect impacts on our business.

Directly, they affect the pricing of our commodity contracts and change our plant’s product mix, thereby potentially further impacting margin contributions. Indirectly, we have seen volatility impact producer decision-making with near-term development delays and broader existing production shut-ins due to lower prompt-month crude pricing and significantly negative Waha natural gas prices. It is a confluence of multiple factors that has led to this unexpected situation. In October, there were days when approximately 20% of volumes were curtailed, of which roughly half were from our oil-focused producers, a dynamic that we haven’t seen since May of 2020, when the WTI crude oil futures contract final settlement price was negative $38 per barrel.

We estimate that full-year earnings are negatively impacted by curtailments by approximately $20 million. While Waha prices are expected to remain an issue, takeaway constraints should begin to alleviate by this time next year. Specifically, the industry is set to bring online over 5 billion cubic feet per day of new takeaway capacity in 2026 and in early 2027 through the following projects: the GCX compression expansion, the Blackcomb pipeline, and the Hugh Brinson Pipeline. Kinetik’s marketing entity reserved transportation capacity to the Gulf Coast in 2025 and 2026 to insulate itself from curtailment-related lost gross margin. However, the curtailments were more severe as we saw oil-focused producers shut in production. Turning back to commodity prices, indirect influence on our business, we estimate that lower crude and natural gas liquids pricing, as well as negative in-basin natural gas pricing, have deferred or changed our customers’ development plans across our system, negatively impacting full-year 2025 EBITDA by approximately $30 million.

While the Permian Basin continues to demonstrate resilience amid broader commodity price and macroeconomic pressures, it is not immune to the current headwinds. Since the beginning of the year, the Delaware Basin rig count has declined by nearly 20%, reflecting a more cautious stance from our producers. This shift in behavior is also being reflected in industry forecasts. For example, the EIA now projects Permian Basin natural gas volumes to be flat from 2025 to 2026 on an exit-to-exit basis compared to approximately 3% growth in 2025 exit to exit and approximately 9% growth in 2025 on a year-over-year basis. Lastly, our guidance assumed a full year of adjusted EBITDA contribution from EPIC Crude. However, with the divestiture closing in October, Kinetik won’t receive the benefit for our pro rata EBITDA for the full fourth quarter.

And of course, this will have some impact on our full-year results. We received over $500 million in cash proceeds from that sale and have used those proceeds to pay down debt, reducing our leverage ratio by approximately 1/4 of a ton. Over time, we will use some of those proceeds to redeploy into new opportunities such as the acid gas injection well that we FID-ed today. Taken together, these impacts led us to revise 2025 adjusted EBITDA guidance to $985 million at the midpoint versus our previous guidance in August. Despite the numerous factors impacting 2025 results and near-term estimates expectations, we remain confident in our long-term strategy and the value creation potential of our organic growth initiatives. Turning to capital guidance.

We are tightening our full-year range to $485 million to $515 million, given our heightened visibility with 2 months of the year remaining and the FID of our Kings Landing acid gas injection project. Before we open the line for Q&A, let me briefly touch on our capital allocation priorities. Our strategy remains firmly anchored in creating long-term shareholder value while maintaining flexibility for disciplined capital deployment. Since Kinetik’s inception in February 2022, we’ve delivered double-digit adjusted EBITDA and free cash flow growth, meaningfully delevered the balance sheet, and returned nearly $1.8 billion to shareholders since the merger. Today, we’re building on that momentum with one of the largest processing footprints in the Delaware Basin and advancing strategic projects like the ECCC pipeline, sour gas treating, and capital-light reinvestment opportunities, all at attractive mid-single-digit setup multiples.

These initiatives, combined with our current total shareholder yield of nearly 11%, underscore our commitment to delivering both near-term results and long-term value. Looking ahead, we see a clear path to long-term value creation through our short-cycle strategic project backlog, supported by a conservatively leveraged balance sheet and continued shareholder returns via dividend growth and share repurchases. This disciplined approach positions Kinetik for sustainable growth and a compelling long-term value proposition. And with that, we can now open up the line for Q&A.

Q&A Session

Operator: [Operator Instructions] We will now take our first question from the line of Brandon Bingham with Scotiabank.

Brandon Bingham: I wanted to just start on the producer delays, if we could. In the release, it sounds like they are shorter-term in nature. Just trying to gauge maybe the impact on next year. Are these kinds of early ’26 POPs that you expect? Do you think they’re incremental to ’26 development schedules, or maybe they’re replacing some POPs that got pushed into ’27 as knock-on impacts? Just trying to get a sense as to where ’26 might be headed from a producer development standpoint.

Jamie Welch: Brandon, it’s Jamie. Thanks for the question. So let’s deal with what we outlined in both prepared remarks and in our press release. So we’re talking about delays as it relates to expected turn-in-line activity during the fourth quarter of this year. So we have seen things move from September now into late November, which is now past the expected maintenance season and into December. So we’ve probably seen maybe one move into early 2026, but not really that significant relative to, I think, things we’ve told you previously. So it’s more about moving things within the quarter, which obviously has a knock-on impact. If you move something 30 days, you’ve moved 1/3 of your quarter. If you move it 60 days, you’ve moved to 2/3 of your quarter.

If everyone is going to look at an annualized $1.2 billion and say, okay, that’s $300 million for a quarter, but now we’ve moved our turn-in-line activity, that obviously has an impact. That’s the easiest way to think about it. So just to clarify, it sounds like it’s not necessarily moving things into ’26. It’s just delayed within the quarter. So most of the benefit happens in ’26. Yes.

Brandon Bingham: And then just one more question. I heard or read some articles recently that one of your larger customers up in the Durango system area was having a lot of success in the Yazo formation. And I was just curious what you’re hearing or seeing up there, and just the development expectations outside of the commodity price volatility. It just sounds like some of those formations are stronger than maybe most would anticipate.

Kris Kindrick: Brandon, this is Kris. Thanks for the question. Look, the Northwest Shelf is an exciting area for our producers up there. The geology is good. Given the price environment, there’s still activity in that area. And so what I would say is we see activity. We have the capabilities to provide sour gas takeaway, which is critical in that area. And we’re excited to continue to grow with our producers on the Northwest Shelf.

Trevor Howard: The other thing that I would add, just following on Kris’ comments, is we’ve seen pretty robust E&P M&A activity up there, which generally portends development once the E&P gets their hands around the specific asset. So that’s one dynamic that we’re seeing on the Northwest Shelf. Another dynamic that we’re seeing is that some of the management teams or private equity companies that had flipped in ’23 and ’24 have returned, and they’re beginning to push the frontier of the Delaware Basin up on the shelf right into our asset footprint. So nothing to report just yet. It’s early days, but some nice green shoots for incremental development that we were not expecting 15 months ago when we acquired the asset.

Jamie Welch: Brandon, it’s Jamie. Not that this was exactly the question or the response to your question, but this is one of the reasons why the AGI for us was so important. Sequencing is everything for Northern Delaware. And we looked at this, and we said, okay, now we have this wonderful new Kings Landing plant. It can deal with sweet gas. It’s got a 600 GPM unit on the GPM amine unit, but it’s limited as to what it can take. What we really need and what we really see is the need for sour gas and our ability to basically treat it and process it. And that obviously brought about the advent of bringing forward the AGI even ahead of King’s Landing, too.

Operator: The next question is from the line of Gabe Moreen with Mizuho.

Gabriel Moreen: If I can ask, Jamie, maybe just staying on 2026, bigger picture. Clearly, you laid out some long-term targets for growth over the next couple of years. I’m just wondering how you’re viewing 2026 sitting within that context, given the push and pull here, the commodity backdrop, and producer plans. So maybe if you can just maybe talk about that a little bit.

Jamie Welch: Yes, sure. Gabe, and thanks for the question. Look, I think like everybody in the context of both our peer group and our producers, we’re all going through the planning and budgeting phase right now as to 2026. No one quite has a crystal ball on exactly how this is all going to look forward as it relates to commodity prices and sort of geopolitical impacts. Obviously, I think if I look at my dear friend, Kees Van Hoff’s most recent stockholder letter, he gauges it as a yellow right now on a traffic light system. And I think that’s right. So ’26 is, for us, we are trying to discern exactly the level of activity. And obviously, we’ll report back with our guidance in February. Most importantly, the framework that we obviously had historically articulated, Kings Landing, is now online.

So if you just tick through the important elements, and then I’m going to give you the qualifier. King’s Landing online for a full year. ECCC will be online for 8 months, 9 months, something in that sort of ZIP code. You have NGL contract expirations, of which there are 2. You will have, obviously, cost reductions. The negatives will be that you will no longer have EPIC, and you will have this question mark on the level of activity in the context of overall development and drill plans for producers. That’s the way to think about it. There are both good and there’s elements, which are EPIC is an unknown, and then there is the question mark with respect to producer activity.

Gabriel Moreen: And maybe if I can just ask a little bit of a multipart follow-up on the natural gas moves you’ve made. First, on getting capacity on the Permian egress pipe in ’28. Is that a question of alleviating Waha exposure since you’re getting an increase from your producers? And did you think about taking an equity stake in the pipe like you’ve traditionally done with some other investments? And on the LNG strategy, I’m just curious whether that is something you’ve been reverse-inquired about from the part of customers? Or is that something that you really just see as allowing you to compete better for additional packages of gas as they come up here?

Jamie Welch: Great series of questions. So let me just deal with the first. We’re simply a contract counterparty on this particular pipeline, and it’s expected to be in service in ’28. We have now today, when we look at our Delaware South system for most or many of our customers, we have been able to offer them egress with Gulf Coast pricing. As we have moved north with Durango or Delaware North, as we obviously now call it, and obviously, with King’s Landing coming online, we are now offering that opportunity for those customers. There is a lot of interest in taking incremental capacity. So you look at how much capacity you have, and you realize we actually need some more because the overall demand is so high. So Kendrick and the commercial team went and secured some more additional capacity, which we know is needed.

On the LNG side, it has been a topic of conversation around our leadership team for some time. If you go from a Waha to a Houston Ship Channel price point, clearly, we can see the overall premium step up. And we have seen it in the early days, when it was not as attractive. And obviously, the last couple of years, it has been highly attractive. A further step out has obviously been on the LNG side. And we have always talked about, okay, the issues on the LNG side, Gabe, I think, are twofold. How do you do something that is manageable as far as size, and two, that you don’t have to take a 20-year contract? Something that is manageable in duration that you can say, and it’s close at hand. So again, I give Kris and the commercial guys a lot of credit; they scoured the earth.

They found a counterparty that had available capacity. We’re talking about 16, 18 months from now. I mean, that’s like a game-changer in the LNG. And when we went to our customers, they were like, Wow, this is really good. Short term, near term, I start getting this price point. I get my arms around it, and it’s a really interesting, I think, step out for us, which I think we’re going to continue. We’ll learn a lot over the course of this, and we expect that we may have other customers who will be very intrigued about using this as one of their pricing diversification.

Operator: The next question is from the line of Jackie Koletas with Goldman Sachs.

Jacqueline Koletas: First, I just wanted to start, commodity exposure has been a major headwind this year. It sounds like some of the project agreements you announced could help hedge that exposure. What is your hedging strategy just throughout the remainder of the year? And how do you expect to mitigate that commodity exposure prior to that firm takeaway agreement in ’28?

Trevor Howard: Thanks for the question, Jackie. This is Trevor. I would say that for 2025, we’re relatively well hedged across most products between C1 through C5 and WTI. As we look forward into 2026, we’ve talked about this in the past, being between 40% to 80% of our equity volumes being hedged on a rolling 12-month basis. I would say that we are within those targets, just where we sit with Waha today, and then with WTI, which has skewed us towards the lower end of that range. But what I would say is that we’re still well within the range that we have been executing on for several years now.

Jacqueline Koletas: And then with the FID of the AGI well expected for the end of ’26, how do you expect volumes to ramp from here on King’s Landing 1, and when we should kind of see that uptick? And how does that impact the timing for the King’s Landing 2 announcement?

Trevor Howard: Yes. So, as Jamie had mentioned, as we think about 2026 and providing explicit directional guidance right now, it’s just a little bit too early. What I would say is that we included this in our prepared remarks. The plant is running more than half full right now. We have several packages of gas that are coming online next week and then in December as well, and into 2026. As we think about planning for Kings Landing 2, that is potentially a 24-month endeavor. And so it’s not necessarily how does 2026 shake out, but it’s more as we look forward in a multiyear plan with our producer customers and also what Kris and the commercial team are doing with signing new packages of gas that really makes us lean over kind of the edge of when we FID that Kings Landing 2 plant. But given the long lead items there, it’s not really a question of what does the next 6 months look like, but how do we think about ’27 as well?

Kris Kindrick: Jackie, I would say, look, this comes back to my earlier comment about the AGI. There are 2 elements in the context of the way we think about the North business. Today, the gas going into Kings Landing is pretty much sweet. We have a 600 GPM amine unit, but that’s it. So we’re not dealing with sour anything like what we do with Maljamar and Dagger Draw. We have ECCC, which is, in fact, a large-diameter sweet gas conduit that can move gas south. So when we think about this and the overall likely development activity, which is predominantly sour, we intend to evacuate gas that right now, you would think about at Kings Landing, it will go down ECCC. You get the AGI in place, you will now convert Kings Landing 1 into a sour gas plant.

And that’s the way to think about the balancing mechanism from a barbell as you look at how you optimize. I think Trevor has always said ECCC, particularly as it relates to sweet gas, gives us the ability to, in fact, be very strategic on the timing for Kings Landing 2. And one thing that I would add is as Jamie’s comment just about development activity being primarily sour. I think that comment more pertains to in and around Kings Landing. With respect to suite development, we’re seeing substantial suite development along ECCC. And to Jamie’s comment, that once ECCC is online in the second quarter of ’26, we will reroute that gas south in order to free up capacity up north.

Operator: The next question is from the line of Jeremy Tonet with JPMorgan.

Jeremy Tonet: Just wanted to follow up on some of the questions that have been asked so far. I think there was a run rate of $1.2 billion EBITDA for exit ’25 that was expected at some point in the past. A lot of moving pieces for ’26, as you said, but do you still expect to hit that $1.2 billion at some point run rate during ’26?

Kris Kindrick: Sorry, during 2026?

Jeremy Tonet: Yes. That $1.2 billion EBITDA run rate, if not hitting it year-end ’25, do you expect to hit it during ’26?

Kris Kindrick: Well, I think what we said, Jeremy, is let’s just park for one second, 2026. I’m happy to sort of articulate some of the challenges in the context of 2025 and how you get from $300 million to the midpoint where you have the revised guide today. But I think primarily, if you’re going to think about it in just easy terms between the shut-ins and the delayed and turn-in-line activity and Epic, you’re well over 60% of your difference.

Jeremy Tonet: And then I guess, just any other thoughts you might be able to share, I guess, there’s give and takes as you lined up there for ’26. But just how do you think about the earnings power of the business, the growth profile over time, when all these variables normalize, settle out, or just from a baseline post that, how do you think about the EBITDA growth potential for the base business?

Kris Kindrick: Look, I think the overall EBITDA growth potential for the business remains very strong, conditioned on we have continuing activity in the context of the development side. And that’s, I think, really the question right now we’re all grappling with. And as we look forward. Obviously, I don’t anticipate, and I think you heard it in remarks from Trevor earlier, that we haven’t seen oil-directed PDP shut in since COVID. This was something that none of us would say on the risk equation, we were otherwise anticipating. We have lived with Apache in the context of knowing that, obviously, when Waha goes negative, they shut in. Got it. We knew that. Rins repeat, we play forward. But this one was a completely new world for us to basically have to try to reconcile.

And as Trevor indicated in his remarks, on some days during October, almost 20% of our overall existing production was actually shut in across the board, of which it was split between the oil, gas, and the oil-directed production, and obviously, Apache on Alpine High. So it was a really strange situation for October. And obviously, we’ve continued to see it bleed into November. Yesterday, minus $1.10 on Waha. Today is obviously still negative. I mean, this isn’t building a lot of confidence. And that being said, October of next year, 5 Bcf a day of egress comes online, just go look at the forwards. Trevor and I were looking at this this morning. It’s like a step change relative to what we see as far as current natural gas pricing. So I think there are a lot of things that the market is probably telling us, one of which is that we do expect softer activity.

We do. And I think that’s allowed us, and that is what has prompted us to think about a fundamental reset. One of your colleagues said, rip the Band-Aid off. Well, we looked at this and said, okay, this was our chance to basically go and really take a really tough look at the overall elements of our forecast and how we forecast it so that we can come out and not continue to perpetuate the last 4 quarters, which have been pretty rough and obviously, something that we’re not pleased or happy with.

Jeremy Tonet: Just last one, if I could, with regards to thoughts on using the buyback in the future. What type of cadence or framework at this point, given volatility in the stock? Just wondering any more thoughts you could share there?

Kris Kindrick: Look, I think on the buyback, the buyback fits within the capital allocation bucket. The capital allocation bucket has 3 masters that, in fact, could satisfy. Buyback, dividend growth, and capital allocation for organic projects. All of the above. And we have to look and see where, in fact, we think from a fundamental value standpoint, where we think and what we truly believe to be in the best interest of all stakeholders. And so we look at that and we sort of make the decision. And obviously, Trevor will do that as we go forward, and we’ll look at the buyback. We’ll be looking at the dividend every quarter. We will be looking at, obviously, ongoing investment in our organic project program.

Operator: The next question is from the line of Keith Stanley with Wolfe Research.

Keith Stanley: I wanted to dig a little into the implied Q4 EBITDA in the new guidance. It’s $250 million at the midpoint. Can you say what does that assume about King’s Landing volumes? I assume there’s no Alpine High in there. And then beyond the shut-ins, were there any adverse impacts from the extreme Waha pricing in October as it relates to gas price exposure in that Q4 number?

Trevor Howard: Thanks, Keith. This is Trevor. As Jamie had mentioned, when you include just customer volumes, that assumes our gas-focused shut-in volume as well as our oil-focused producers shut-in volume, as well as timing delays with respect to — given the fact that Waha in certain days in October was minus $9, that caused several producers to push development, as Jamie had commented earlier into later in the quarter. When you couple that with the EPIC sale, that represented over 60% of the revision, lower. What I would say is that there’s that element. And then yes, there is an element of pricing. As you know, a portion of our equity volumes on C1 is priced in basin locally. And that did have a negative impact as we looked at the fourth quarter forecast versus where we were 3 months ago. So that certainly had an element to it. I wouldn’t necessarily say that, that was nearly the impact that we saw in just the lost gross margin from curtailments across the system.

Jamie Welch: As far as the overall run rate into King’s Landing, King’s Landing is now at that point where we’re turning around individual compressor stations and basically bringing on gas that has, to this point, been curtailed. So there is more to happen. I think there are another couple, if I’m not mistaken, or at least one over the course of the next 4 to 6 weeks, that’s likely to happen. So that will bring more volume on. And then it’s going to be a question of, okay, do the oil-focused producers, both in the North and in the South, we’ve had shut-in production from both categories. And therefore, the question is, okay, are they going to return? And if so, what’s that timing look like?

Keith Stanley: And to confirm that when you say over 60% is explained by those factors, the difference between the new guidance and the $300 million quarterly rate?

Trevor Howard: Yes, exactly. That’s right. Exactly.

Keith Stanley: Second question, how are you thinking about recontracting on TNF in light of recent industry developments? You have Speedway being built, Energy Transfer saying last night, they might convert an NGL pipe to gas service. Does it make sense to try and recontract some of your expirations now and do shorter-term deals? Or would you wait until they actually expire?

Jamie Welch: Keith, it’s Jamie. I think the following. 2026 is the first time that we get to the point where we’ve got expirations. And we are obviously very much aware of the current market dynamics. I think, yes, even with whether you do a conversion, you’re obviously adding Speedway, obviously, I think there’s an expectation that there will be less production. So I think still the overall bias for T&F rates will be in favor of the seller. And there’s a lot of infrastructure that is being built that will need to be filled up. So I think from our vantage point, we don’t see any changes to, look, we will deal with this over the passage of 2026 as we get to it. And as I said, I think our viewpoint is that the market dynamic will not change between now and then, and we still see this being a very attractive opportunity for us.

Operator: The next question is from the line of Michael Blum with Wells Fargo.

Michael Blum: I wanted to go back to the Waha issue for a second. Just more of a clarification, I think, for me. So you’ve secured some additional capacity to the Gulf Coast in 2028. So what exactly are you doing to manage your exposure between now and then?

Kris Kindrick: So we have our existing capacity today. We have more capacity next year. And then we have this new tranche of capacity, which comes on for 2028. So we have always been actively managing it, and we are looking forward in the context of how we look at the overall needs of our customers and what that overall expected growth rate is as far as the amount of volume that wants to be settled at a Gulf Coast price. So, we’ve got capacity, as you know, and we’ve said that repeatedly. And so we manage it, and this will just be another tranche that we will basically add to our overall portfolio.

Michael Blum: And then maybe on a related item, and you hinted at this in your prepared remarks, I think. But you had talked in the past about an in-basin power project with some of your producer customers as a way to manage some of this Waha exposure. Can you give us an update on where that stands today?

Kris Kindrick: Sure. So we have continued to obviously talk to our upstream customers. I think it wouldn’t surprise anyone to think that in the current environment, where capital is, I think, being heavily scrutinized, that this is a nice-to-have for them versus a need to have. I think we look at it and say this is very important for us to, in fact, help us address controllable costs. Obviously, electricity for us has been a rising cost over the course and passage of 2025. And so we continue to evaluate it. I think, look, more to come. I think we should show it in our presentation materials that it’s active development. We’re getting all of the equipment organized. I think there will be more to communicate to everybody over the passage of the next short time period.

Operator: The next question is from the line of Samya Jain with UBS.

Unknown Analyst: Could you provide more color on the data center-related infrastructure investments you might be seeing across the New Mexico border and how Kinetik might be positioned to capture that market? I know we recently saw Oracle and OpenAI announce a data center campus planned in Southern New Mexico, and that will probably use Permian gas. So how might Kinetik’s current footprint facilitate that sort of project? And how could sour gas come into play?

Trevor Howard: Samya, thanks for the question. I think I would look at the data center opportunity for us as being one where we have the ability to connect a residue gas pipeline network into a power generation source dedicated to a potential data center or large demand side customer. Obviously, there are a lot of projects, as many of you know, in the TEF, the Texas Energy Fund, that obviously are looking to get to FID. One project was obviously the CPV project. We provide one of the main gateways for gas to go to a 1,350-megawatt plant that is now broken ground, FID-ed, and expected to be in service in 2029. We believe that there will be other opportunities for us like that, that will then not only provide us connectivity because we’ll be building out our pipeline network, but also provide us the opportunity to deliver and supply gas, whether it’s in the form of us as Kinetik or our customers that may sit behind our plant or our processing facilities.

So I do think there is a lot of interesting. Stay tuned. There’ll be a lot more discussion on these particular topics. But this one was sort of the most immediate. We just got it completed. We’ve been working on this for 2 years or something. So it’s been a long time coming, but I think there are some pretty interesting opportunities, and we get approached by many. There are many people who are approaching us on the power gen side who want to do large-scale gas by CCGTs.

Kris Kindrick: Samya, this is Kris. A lot of our residue gas infrastructure that’s owned and operated is in the Southern Delaware. We’ve been talking to many parties. One of them, which was publicly announced recently, the Landbridge NRG deal is adjacent to Delaware Link. So we’re having conversations there. So again, we’ll see which ones completely make FID, but we are having conversations with a number of folks, like Jamie alluded to.

Unknown Analyst: And then I understand that many of the customers you gained from the Durango acquisition are private. So, how have you seen drilling activity in the Permian vary between private and public producers? And as you develop your footprint in Delaware North, what sort of customers are you seeing more traction with down the line?

Trevor Howard: Thanks for the question, Samya. This is Trevor. What I would say is that the private producers that we’ve seen have been, I’d say, a little bit more price sensitive, particularly in this current environment, than some of the publics. They’re not putting out multiyear production targets. And so they tend to be, again, a little bit more volatile with respect to the ups and the downs. However, what we have seen just with experience, we saw this during COVID, is that as crude lifted off the bottom, they were the first to pick the rigs back up and be very aggressive, particularly one of our customers, large customers up there. So I would say that is just a general macro comment that we’re seeing. With respect to what we’re seeing from customers up north, I’d say it’s a nice mix of both the private equity-backed and private companies that are aggressively moving up there to expand the play and also seek inventory, given that it’s pretty competitive.

It’s extremely competitive down towards the state line for someone to go pick up inventory. The other thing that we’re seeing is that we’re seeing some of the publics that have historically been more focused on the state line or in Texas push further north, just given what they’re seeing from well results across all formations. So it’s a pretty attractive and it’s part of our thesis that we have with Durango. It’s a pretty attractive development that we’re seeing right now. And it’s a multiyear strategy that we have here in order to continue to build this beachhead position and capture a lot of market share as the play continues to move further north, east, and west.

Kris Kindrick: And Samya, this is Kris. We’re still seeing the dynamic, too. You asked about Northern Delaware. You go to the Southern Delaware, where if there’s acreage that some of the public don’t want to drill, we’re seeing some of the private farm that out and pick that up and drill that. So there’s still that dynamic going on. So there’s a good mix of development we’re seeing activity from private. So that’s continued to happen on our system.

Operator: This will conclude the question-and-answer portion of today’s call. I would now like to turn the call back to Jamie Welch for any additional comments.

Jamie Welch: Thank you, everyone, for your time this morning, and we look forward to continuing our dialogue and engagement with you over the coming days, weeks, and months. Thanks.

Operator: This concludes today’s conference call. Thank you all for your participation. You may now disconnect your lines.