Kinetik Holdings Inc Stock

Hello, everyone. My name is Janine, and I will be your conference operator for today. At this time, I would like to welcome everyone to the Kinetik Third Quarter 2026 Results Conference Call. [Operator Instructions]

And with that, I would now like to turn the call over to Alex Durkee to begin the conference. Please go ahead.

Good morning, and welcome to Kinetik's Third Quarter 2026 Earnings Conference Call. Our speakers today are Jamie Welch, President and Chief Executive Officer; and Trevor Howard, Senior Vice President and Chief Financial Officer.

As a reminder, today's discussion will include forward-looking statements. Please refer to our SEC filings for a discussion of the risks that could cause actual results to differ materially. We will also reference certain non-GAAP financial measures. Reconciliations can be found in our earnings materials and on our website.

With that, I will turn the call over to Jamie.

Thank you, Alex. Good morning, everyone. The third quarter was another strong step forward for Kinetik. Record processed gas volumes, strong system performance and improving producer activity supported our results as the impact of price-related curtailments diminished.

Our outlook has strengthened and producer development plans give us greater confidence in our growth trajectory. That confidence supports our expectation that 2026 adjusted EBITDA will be at the high end of our guidance range.

We are strong believers that the Permian's best days are still ahead. Producer activity is increasingly extending beyond the traditional core oil benches into gassier formations with higher gas-to-oil ratios, including the Woodford, Avalon, First Bone Spring and Penn Shale. These development trends are significantly increasing demand for gathering, processing and treating capacity and play directly to the strengths of our integrated footprint.

At the same time, localized Waha egress constraints have begun to ease. In just the last 3 months, over 7 billion cubic feet per day of new Permian pipeline egress capacity has been announced, and we now expect more than 13 billion cubic feet per day of incremental residue gas takeaway capacity to come online from 2028 through 2030, providing the downstream infrastructure necessary to support the next phase of Permian Basin growth.

Against that backdrop and based on our own systems current utilization, it is increasingly clear that additional processing infrastructure is needed to keep pace with expected producer activity. KL1 and our other New Mexico processing complexes operated at full capacity for much of the third quarter. And so ECCC flowed surplus volumes south.

In September, we elected to upsize KLII from the originally planned 300 million cubic feet per day to 380 million cubic feet per day of processing capacity with no increase to the approximately $260 million expected project cost.

Our operations team successfully procured key equipment at a low expected cost, allowing us to acquire the additional residue compression required to support the larger design while maintaining project economics.

KLII remains on track for mid-2028 in service. We are also investing in targeted projects that add incremental system capacity and operating flexibility across the system. For example, at Pecos Bend, we're undertaking treating upgrades that will support higher inlet CO2 concentrations and additional volumes moving into Delaware South.

And we're also procuring additional compression equipment to be deployed across our gathering system to further support growing producer volumes and proactively manage our supply chain.

Our commercial results provide compelling evidence. We built on a successful first half of the year with another quarter of solid commercial execution. Since August, we have executed new and amended gathering and processing agreements across New Mexico and Texas, adding more than 30,000 gross dedicated acres across our footprint, with first flow expected in the second and third quarters of 2027.

A portion of this acreage is prospective for the Woodford formation, an emerging gas-weighted play that we believe has the potential to drive meaningful long-term volume growth across our system. These agreements further validate the competitive advantages of our business, including our extensive Delaware Basin footprint, robust treating capabilities, operational reliability and differentiated premium netback offering.

As these new volumes layer in alongside ongoing customer development, we will continue to utilize all available means to cost effectively expand our operating processing capacity, be it with plant modifications and/or boost recompression.

Now, even with these initiatives, we expect to reach full utilization across our integrated system by the end of 2027. And to that end, the Phase I expansion of ECCC will be an important bridge. That expansion will allow us to move incremental volumes south to Texas to optimize our processing capacity utilization until KLII enters service and will give us flexibility on managing third-party offloads.

I want to be clear, the opportunity we see in 2027 is not simply a volume story. The vast majority of our expected growth next year is anticipated to come from higher-margin, low-pressure developments, which support an increase in our unit fee margins.

In addition, our legacy Lone Star NGL contracts in Texas and New Mexico begin expiring this quarter with the first expiration on October 31 and further expirations at the end of this year and September 2027. These expirations will drive greater gross margin growth in 2027 than we had previously intimated.

Importantly, these are all business-specific drivers, largely independent of commodity prices, and we expect them to meaningfully improve unit gross margins and our 2027 EBITDA and cash flow growth.

Looking further out, the recent commercial commitments and robust producer development activity improve our visibility beyond KLII. To keep pace with our customers' long-term development plans, we ordered long lead residue compression equipment, and we are now procuring front-end amine and the actual 400 million cubic feet per day cryo itself for our next gas processing facility.

Continued commercial success and execution will accelerate the timing of that subsequent processing expansion. Taken together, we see a clear path to continued volume growth, improving margins, robust financial health and high conviction in our near-term and medium-term outlook.

Favorable basin dynamics, accelerating commercial momentum and the strategic advantages of our integrated platform continue to reinforce one another, expanding both the scale of our opportunity set and the duration of our growth runway. We remain highly confident in our outlook and our ability to create meaningful value for shareholders.

And with that, I will turn the call over to Trevor.

Thank you, Jamie. For the third quarter, Kinetik reported adjusted EBITDA of $278 million. Distributable cash flow was $214 million. Capital expenditures were $131 million and free cash flow was $88 million.

Within Midstream Logistics, adjusted EBITDA increased 34% year-over-year to $204 million. Processed natural gas volumes were 1.94 billion cubic feet per day with an estimated 25 million cubic feet per day of Waha price-related shut-ins on average during the quarter.

Sequentially, results benefited from higher processed gas volumes, continued strength in system operating performance and favorable commodity margin realization. Meanwhile, Gulf Coast marketing margin declined as expected with Waha natural gas prices improving to positive territory.

Our Pipeline Transportation segment generated adjusted EBITDA of $79 million, down 18% year-over-year. The decline primarily reflects the late 2025 divestiture of our equity interest in EPIC Crude and higher fuel costs at Permian Highway Pipeline and lower throughput volumes at the Shin Oak NGL pipeline. However, volumes on Shin Oak continue to outperform original budget expectations.

At quarter end, net debt was approximately $3.9 billion, liquidity was $1.1 billion, and our leverage improved to 3.7x.

Turning to the outlook. We now expect full year 2026 adjusted EBITDA to be at the high end of our EBITDA guidance range. Third quarter results exceeded our internal expectations, driven primarily by commodity margin and fee realization. While our business remains predominantly fee-based and we are well hedged across products through year-end, commodity prices have remained above our August guidance assumptions and continue to provide incremental upside.

We expect higher gas fee gross margin and operating performance to continue to support into the fourth quarter. Processed gas volumes continue to track toward our target of approximately 2.2 billion cubic feet per day in the fourth quarter. Additionally, crude and water fee gross margin as well as operating expenses remained largely in line with our expectations.

We now expect full year 2026 capital expenditures, including maintenance capital, to come in approximately 5% below our guidance of approximately $560 million. The lower expected spending reflects favorable project execution, operational efficiencies, disciplined cost management, the timing of certain project payments now expected to occur in 2027 and also includes the purchase of incremental compression equipment that Jamie discussed earlier.

Looking to 2027, beyond the volume and margin drivers Jamie described, we expect a constructive commodity environment to support gross margin, partially offset by lower residue gas marketing contributions.

Earnings and distributable cash flow have grown significantly throughout the year, and we have made material progress in achieving our financial framework milestones. Dividend coverage improved to 1.6x in the third quarter, up from 1.5x in the second quarter.

Consistent with our framework, we plan to sustain coverage of 1.6x or greater for several quarters before growing the dividend more closely in line with our earnings outlook. In the meantime, we currently anticipate a recommendation at the high end of our targeted annual 3% to 5% increase for the fourth quarter dividend that we expect to declare on our regular cadence in January 2027.

Leverage is following a similar path. We ended the quarter at 3.7x and based on our current outlook, expect to exit the year at the low end of our 3.5 to 4.0x target range on an annualized quarterly EBITDA basis. That progress positions us well as we continue to execute our growth-oriented framework -- when we introduced it earlier this year, we said we expected elevated growth capital driven by high-return projects backed by long-term commercial agreements.

With customer activity already pointing to processing needs beyond KLII, we continue to expect growth capital to likely remain elevated as we advance strategic projects across our system. Our capital allocation priorities remain unchanged: fund attractive high-return organic growth projects, maintain a resilient balance sheet and return capital to shareholders through a growing well-covered dividend.

What has changed is the pace. Progress across these objectives is really exceeding our prior expectations, giving us greater capacity to fund growth and return capital while maintaining balance sheet discipline.

Operator, we can now open the line for questions.

Thank you. We will now begin the question and answer session. [Operator Instructions] Our first question comes from the line of Theresa Chen from Barclays.

I wanted to go back to the margin outlook, Jamie. With the AGI and sour gas conversion project expected online around year-end, can you help us frame more quantitatively the potential margin uplift in 2027? And as increasingly sour volumes come on to your system, how should we think about the benefit from treating economics and your ability to optimize between Delaware North and South?

Thanks for the question, Theresa. This is Trevor. We've never explicitly stated how much that project is, but a fair way to think about the Phase I for the project is approximately $100 million. Typically, we underwrite the organic investment at a mid-single-digit investment multiple, so 5 to 6x. I think that's a fair assumption as you think about gross margin contribution beginning at the end of this year and for a full year in 2027.

I would remind you that, that's a -- that's a 20-day permitted total asset gas injection well, and we expect to utilize initially in 2027, only about 20% of that well. And so there's tremendous operating leverage, and that has the potential to be a really attractive interesting project as volumes come on of the system beyond 2027. But we are really pleased when we originally underwrote this back in 2025 with the setup only utilizing about 20% of the permitted capacity.

Great. And with your progress to exit the year around 2.2 Bcf per day of inlet volumes with the system approaching full utilization second half of next year, how should we think about the cadence of volume growth through 2027 and beyond really taking into account the new G&P agreements announced?

Theresa, it's Jamie. As far as the overall level of growth, I think it will be best manifested by the cadence you see with the announcements on processing capacity. And I think what we had originally expected and anticipated and communicated to folks was every 18 to 24 months, we would add an additional cryo.

There was a time we would focus on 200 a day. We obviously now have migrated to 400 a day. So said another way, our growth -- our volume growth expectations have doubled relative to where we were. That should give you a perspective and insight as to what we are seeing both as it relates to New Mexico, but also in Texas.

So that's 400 a day every 18 to 24 months is a big step-up from where we originally were.

Our next question comes from the line of Spiro Dounis from Citigroup.

I want to add on to that question a little bit. Maybe just stick with processing capacity here. So trajectory strong into next year, ECCC expansion helps deal with some of this expanded volume. But you also talked about those expansions across your legacy processing plants that it sounds like are still going to end up filling up by the end of the year. So curious, can you remind us how much processing expansion upside there is on that current system and how you think about maybe the CapEx and timing to extract all that extra capacity?

CapEx is relatively small. The overall -- we've already undertaken some small projects. I would say sort of what remains to go is somewhere in the order of probably 50 a day of incremental. If our guys can basically push any more out, they'll obviously look at it. But we look at it on a value engineering basis, meaning what's the value of the upside of the capacity upside and how much does it cost to get it? And how quickly can we get it?

All of this is stuff that we actually anticipate over the course of the next 6 months should be done. So it's not a long lead time. It's things we've been building up. Honestly, it's been on the draw board -- on the drawing board for quite some time. So now we're basically -- as we undertake any maintenance events, we're obviously looking to basically swap out equipment and whether it's rebuilding center blocks or whether it's adding a boost recompression, -- all of that is basically contemplated over the course of the next 6-plus months.

Got it. Got it. Great. Second question, just going to the dividend. Trevor, you said achieved your 1.6x coverage ratio, which allows you to accelerate the growth there. I appreciate that it's a Board decision and probably a few quarters away. But is there a maybe sort of secondary framework you can help expand on to help us understand how much you'd be willing to accelerate to? And then just what you're watching before you sort of make that decision?

Thanks for the question. What I would say is that typically, we recommend a dividend increase at the beginning of each year. And so that's announced in January, paid in February. So that would be the fourth quarter of this year dividend.

Look, we just hit 1.6x. If you were to add a pretty significant dividend increase, that would put you below 1.6x. And so the way that we're thinking about it is that historically, we've said 3% to 5% of annual dividend growth given the performance of this year, where we're trending, balance sheet health and also dividend coverage trajectory, management is more comfortable with being at the high end of that 3% to 5% range for the increase in January, and then we will reevaluate with each quarter thereafter.

I think, Spiro, one of the things that we're grappling with right now is we are going to remain with an elevated capital program going into 2027. And I think our viewpoint is, look, you can put $0.04 on the Board and put it back into a shareholders' pocket. No problem, right? $0.81 can become $0.85.

I think the difference for us, though, is we continue to see this step change going to 2027. And therefore, it is important for us to continue to focus on that execution for 2027 since it is such a significant step-up relative to what everyone has experienced to date that let us get through 2027 and then we can obviously think about what our dividend protocol and process and dividend rate needs to be going forward.

Got it. Helpful color.

Our next question comes from the line of Brandon Bingham from Scotiabank.

You mentioned the increased prospectivity of secondary benches. Would just be curious to hear what sort of early results you're seeing and maybe how much of '27 volumes that you're expecting internally could be driven by a higher weighting of these benches and development plans?

Yes, sure. Brandon, I think, look, what is interesting to us, and we said it in our prepared remarks as well as in the press release itself, Avalon, First Bone, Woodford, Woodford is obviously, as it relates to Texas, Woodford obviously has quite the buzz related to -- we heard it with Diamondback. We've seen their aggregation of acreage more in the Midland, but very much premised or predicated on a Woodford formation and that development potential.

We have a number of our large customers that have some pretty interesting and exciting developments planned for the Woodford. That from a gas gatherer and processor is like Christmas came up all at once because it is just so much gas. It still has good GPMs to it. It's probably around 4 GPM. So it's a little leaner than some of the other gas we have on the system. but it is such volume.

It is literally -- it's raining gas, gas core. I think as far as some of the other secondary benches and what we're seeing, Penn Shale is a really exciting area when we migrate up to New Mexico, and that's probably where we start to see some really interesting opportunities. And the beauty of our system is we're sort of perfectly positioned in both. And that makes for -- literally, it's a great commercial opportunity.

It's a great opportunity for us to obviously capitalize on a lot of our producers' execution and their overall potential.

One other thing, Brandon, that I would just add, I like kind of -- I like going back to where the basin was and then where we are today. So in 2018, crude production in the basin grew by 1 million barrels a day, and that drove roughly 2.3 Bcf a day of gas growth.

In 2027, the EIA forecasts about 2.5 Bcf a day of gas growth, so equivalent with 2018 levels and crude growth of only 330,000 barrels a day. And so what we have seen recently is that we have -- the GORs have compounded at about 5% to 6% per year, and we expect that to not just to continue, but actually the potential to accelerate as these deeper benches start to get unlocked given it is a step change in GORs.

Okay. Very helpful. And then maybe just thinking about development activity, this might be more of a thought exercise than anything, but producer development activity has been relatively stable in light of $100 oil, give or take, with the Permian seems to be more dictated by Waha at least this year. Could you share your thoughts or maybe any customer sentiment or discussions that you've had around what development could do if crude moves lower quickly next year?

Yes. Look, I think when we look out across the board, obviously, there's an opportunity just given where the overall strip is that you can hedge a lot of potential production. I think in New Mexico, in particular, it is -- Trevor likes to call it a baked cake. So we sort of do know what 2027 looks like because you've got a lot more protocols in place that need to be complied with and abate in the context of overall development cadence and timing.

So I think for us, the way we look at it is even at $88, which obviously is a lucky number in Chinese culture, I think it's still a very, very good outcome. And even if we start to see a trend down, the question, I don't really see much change in behavior certainly going into 2027, 2028, obviously, TBD, but I really do think 2027 for now is looking very much like it's baked.

And what we saw during the course of this year because we've been very consistent -- our big customers said, yes, we see prompt month, we see where it is. We can try to basically bring on development pads 30 days, 60 days earlier than anticipated, but don't expect significant changes. The changes that we saw on timing are end of 2027 into mid-2027, mid-2027 to the beginning of 2027. It's '27 that is very much, I would say, certainly for us, don't know about our other peers, but this is where we're seeing our producers really it's going to be the game changer, right?

That's where you're going to see the volume growth that to this point, you've seen it a little bit around the edges, but not so much. 2027 is where you're going to see a pronounced differential.

Yeah, now that makes sense.

Our next question comes from the line of Gabe Daoud from Truist.

I was hoping we could maybe similar to Brandon's question, just talk a little bit about the Permian gas outlook. Diamondback said on their call, they expect the 2030s, the Permian to be the largest gas play in the country, and no one has really targeted gas formations yet.

Obviously, Waha improves and the Woodford makes a lot of gas, as you said, but still driven the Permian in general by oil economics, obviously. So Jamie, I guess I'm just curious, are you hearing anyone talk about the improvement in Waha driving maybe more of a focal point on gas zones even beyond what you've highlighted and really increasing gas-directed drilling in the Permian?

Well, I think the fact that we have -- Solitude gets announced as a Twin 48 and then within a space of 6 weeks, we have Kinder announced Permian Link. The fact you're continuing to see Permian egress pipes should, in fact, give a pretty clear path to any interested observers and pundits on the Permian. There's a lot of gas growth.

And I think we saw Case's stockholder letter for the third quarter. I actually agree with it. We've been saying this for some time. We said come the 2030s, the single largest gas basin in this country will be the Permian. No one believes us or believes us. I still think people question it.

But the fact that we've got 13 Bcf a day of pipelines that literally are basically coming into service over the passage of the next handful of years. I think, hopefully, at some point, people realize that this is real. And if you can get cost down, controllable costs on a drilled lateral footage basis and make it cost competitive, I really do think this is where you're going to see a significant amount of incremental gas production and continue to see as evidenced by how quickly these pipelines get announced.

Unlike when you're in the Marcellus Utica or anywhere else that you've got to do an interstate, you've got a lot more activity and long duration. So I do think our viewpoint is we're just -- right now, we are just testing the surface of the real gas formations. The Woodford obviously seems to have captured a lot of attention in Texas, Penn Shale in New Mexico. This is where it's going.

The -- those 2 bench formations will become common vernacular for everyone inside 12 months. Everyone will think about it and not even look at this as being something new and different. It will just become part of just overall expectation.

Gabe, the other thing that I would just jump in here is that I'd say historically, people have looked at the economics of them in the Permian Basin as being gas or oil. And I think our belief is that it's really -- it's co-products. There are parts of the Woodford that are 1,000 barrels a day of oil, 1,500 barrels a day of oil, but also have a 15- to 20 a day rich gas stream. And so that 15- to 20-day rich gas stream is pretty dang significant and just helps the economics that much further.

And then the same is true on more gassier windows of the Woodford. You might have 1.5 million EUR NGL barrel, but 20 to 25 a day of rich gas production. So pretty significant dry gas volumes as well as pretty significant NGL yields. So there are dry gas windows and that ultimately may be the case happen. But the way that we think about this is just you've had over 5 Bcf a day of demand pull pipes get FID between DSW and Permian Link.

That potentially is going to elicit a price response, which then elicits supply response, not just within the Permian, but also across the Lower 48, which brings you back to your cost curve. And if you have comparable Haynesville sized wells at comparable costs, but also have a liquid stream or even a crude stream. These are just more economic wells.

And so at the end of the day, in the commodities business, the low-cost operator wins, the lower breakeven wins. And so we really like where we sit just from a perspective of how is this capacity going to get filled over time and into the 2030s.

Awesome. That's really good color, guys. And as a follow-up, just higher-level question. There's been a lot of G&P M&A in the Permian in the last several months. Just would love to get, Jamie, I guess, your updated perspective on inorganic opportunities and just the amount of activity that we've seen?

Sure. We continue to see lots of activity, right? We look at everything. Our viewpoint is at the multiples and values being ascribed to existing assets, our focus and attention needs to continue on our organic growth program, where you can deploy capital at mid-single digits, 4 to 6x, 5x on a setup basis, then that's where you should be investing and that's going to create the most amount of value for shareholders. And so we really like the abundance of opportunities we have.

We've got now Kings Landing II out there. So that's going to increase our capacity stack by 15%. If we do the next -- we announce the next cryo, that will raise that to over 30% of our installed capacity being built. So the leaps and bounds on the underlying growth that we see is pretty significant.

Got it. Thanks, Jamie. Very helpful.

Our next question comes from the line of Gabriel Moreen from Mizuho.

I just wondered if you can maybe talk a little bit more about the new NGL agreements. And I think the language on doing better than expected. Just curious on your approach on contracting. Does that mean you kind of lock stuff in medium to long term since I think given all the gas talk here stands to reason and there's a lot of NGLs coming as well.

Yes, sure. Thanks, Gabe. What we had said and we said to anticipate and an illustration we gave is between '27 and 2030, we'd see about $150 million of margin, basically aggregate cumulative margin. If you're looking at breaking it down on a ratable basis, think about it as $40 million a year. The easiest way to think about it and the reason we put the statement in the press release is because we're probably looking at over 50% increase relative to that '27.

So that was -- that's why we said, listen, we've got a pull forward on volumes. We've got recontracting rates, which were better than we anticipated, some total of which is obviously accelerating the benefit, particularly as it gets into 2027.

Then as far as duration of the contracts, we've got flexibility. We've got a lot of flexibility both in the North and in the South on the term structure. And these are obviously highly cost-effective rates. So I think we haven't given exact term date for it, if you will. But I think, look, we've got flexibility with all of these contracts, and they give us the right runway to capitalize on what we're seeing around us.

Maybe if I could just follow up. I think last year around this time when you announced the deal with ENEOS, you didn't probably contemplate $30 an MMBtu LNG pricing. But can you maybe talk about whether that has any impact for you guys with that deal? And just also within the broader picture of creative solutions for producers, whether it's in-basin or out-of-basin LNG, can you talk about any other things you may be working on that front?

Sure. So Gabe, as far as ENEOS, I'm glad you raised it. Obviously, yes, we didn't anticipate it would be where it is. It obviously will have a -- it will be a contributor to 2027 and the growth that we have. Obviously, the question is what's the timing for Port Arthur to reach in service.

We have been saying for some time that what we saw from just a macro price standpoint, Waha was a bottleneck and therefore, there was value destruction. With all of the egress pipes to Houston Ship and Agua Dulce, obviously, that provided the relief valve for gas and obviously helped a lot. We continue to think outside the box and say, look, TTF, JKM, what are the opportunities there for our customers and how can we capitalize on this abundance of gas supply that we control, right residue gas that we control.

And so I think we continue to look at multiple deals, and I think more to come, but we are big proponents. I think we see a lot on the gas side, very similar to what Case does with Diamondback in the context of thinking about how do you maximize the value of gas and the gas molecule coming out of West Texas.

Can I squeeze one more in just in terms of '27 being big. Does that mean you've done a lot of hedging on the commodity side with the curve having moved up here of late?

Yes, Gabe, thanks for the question. It's Trevor. Look, we had communicated previously that we have a ratable hedging program that looks out up to 24 months. What I would say is that we've continued with that ratable program, but we do have some flexibility to flex between the mins and the maxes. And as we've been approaching 2027, we've been pretty active on the hedging front as we look out into '27 and '28.

Appreciate it.

Our next question comes from the line of John Mackay from Goldman Sachs.

I want to go back to the 2.2 Bcf a day volume guide for next quarter -- for fourth quarter. Just any color you can give us on kind of the implied step-up over third quarter? It's pretty material. So maybe just give us some of the kind of building blocks to get from the 1.94. And then any kind of view on how that can progress into '27 would be great.

John, thank you for asking this question. We saw -- I saw it in your note last night and I'm like, I hope you asked this question. All right. So maybe for all these listeners since everyone seems so obsessed with this, our average for October was 2.14 Bcf a day. 200 million cubic feet a day higher than your third quarter average. And we had some MVC deficiencies on top, about 25. Now they got the rest of the quarter to catch up.

So you are proverbially, as Rich Kinder would once say, on the lip of the cup. And my hope is that this -- I've seen it, whether it's you, whether it's obviously Keith, all the other analysts obviously focused on this, and we get it. But I think, look, the volume is there, and that is an actual average number for the month of October. There we go.

Jamie, that's crystal clear. We appreciate it. Second one...

I mean I understood Yes, exactly. We understood the 194 and how do you bridge it. So we were just hoping that someone would ask us and there's your answer. So hey, hopefully, that alleviates a lot of concern.

Absolutely clear. We appreciate it. Just a quick last one for me. And you touched on the next trial a little bit, but maybe just again, like walk us through kind of milestones ahead of that, that you want us to watch.

Look, I think it's -- I think from our vantage point, it continues to be -- we've got a pretty good, as I said, baked cake as it relates to 2027 right now. I think the commercial team with Ross with Trevor and Ross and Nick are very much focused on what is 2028 and how does that change? And a lot of that's going to be geopolitics, macro, we get it.

And then we've got -- there's a number of other commercial opportunities if we're able to -- if we were fortunate to basically harvest and secure those. All of that is the dynamic that literally then creates the impetus to say, times come. We got to get this online. This needs -- is the date we need to hit it. We didn't -- we know that from our experiences with KLII, residue recompression, finer naming and the cryo long lead items.

Civil construction, not a problem. Securing the site is a decision. We have several different opportunities that we could actually go and capitalize on. And so to us, it's all going to be dependent upon how -- what is that -- how quickly do we need something and what's the location best suited to the gas sources that we're looking to basically gather and process.

Our next question comes from the line of Julien Dumoulin-Smith from Jefferies.

It's Alex Overmeer on for Julien. Maybe just going back to gross margins and growth that you guys are expecting in 2027. Is the growth that you're expecting in 2027, could we say that's relative to the third quarter, which is maybe more normalized gross margins now the Waha curtailments are effectively resolved?

Not so much, Alex, because you're going to have -- obviously, embedded in the gross margin will obviously be the NGL uplift. You'll have the first phase of Kings Landing the South conversion of Kings Landing. You'll continue -- it's really the mix of gas.

Most of our gas is low pressure, right? We have more limited high-pressure outlets. And low pressure is where we see incremental treating fees, compression, gathering. So you've got a bundle of services that you provide to the customer. So I don't think just taking the third quarter and saying, well, this is the new watermark is necessarily reflective of how you think about '27.

I think what Trevor's commentary was that unit margin will continue to go up into 2027. And 2027 will be as much about a unit margin increase as it is about volume increases.

Got you. That's super helpful. And then just really quickly on OpEx. Is it fair to assume that kind of $78 million to $80 million run rate per quarter into 2027 as well?

Look, there will be some step-ups at the beginning of the year and then also throughout the year, just in regular way cost escalations. We also...

And things like that, right?

Yes. Just cost of living adjustments, merit adjustments that happen at the beginning of the year. We do have some term contracts that have baked in escalators on some of our rental equipment. That will step up middle of the year. That's offset with what we expect to be some benefits on the electricity side.

So net-net, I'd say it's directionally up, but just I'd say in general, just with escalation and then also in terms of just volume growth, that's also going to increase your overall just total OpEx.

Next question comes from the line of Elvira Scotto from RBC Capital Markets.

So KLII was upsized by over 25% to 380 million cubic feet a day, but CapEx stayed at $260 million. You attributed the savings to equipment components coming under budget. Should we kind of think of this as a permanent step down in per MMcf per day build cost? Were there some onetime procurement wins? And then can you frame the expected CapEx cost range on new cryo relative to sort of the KLII $260 million?

Yes, sure. Elvira, it's Jamie. So I think as far as KLII, you're right in everything you just stated as far as procurement of some of the major pieces of equipment were lower than the AFE. And therefore, we were able to get additional residue compression as well as slightly changed the configuration for the plant to achieve the 380 million cubic feet a day.

As far as your question on how do we think about going forward, I think, look, it is very much going to be dependent upon where you're locating a plant. So I think your range is as you get to a brownfield versus a greenfield, and let's just make the assumption that there's available power, which I think is one of the big questions, in the range of $200 million to $250 -- that's how you think about it. So -- and that's for $400 million. And what Matt and the ops teams would tell you is the brownfield, if you get after it and you can secure the amine and the cryo and the compression, you could be done in 12, 15 months. So it's really -- that's speed to execution, right? But that's predicated on securing those big component pieces where I think you're then looking for a greenfield more in the 18 to 24.

Got it. Got it. My next question is kind of higher level, and you touched on this a little bit. It seems like you have a lot of visibility into 2027, and it looks like that could be a pretty significant growth year for Kinetik. And I understand there's a lot of moving pieces when you think about 2028 and beyond. But if we assume geopolitical, right, I mean, say, Iran gets figured out.

And let's just say oil settles at sort of $70 to $80. I mean, would you have -- when we think about visibility into growth beyond 2027, how should we think about that? I mean, on the volume side, would you -- would your volume growth be trending above where sort of Permian gas volume growth expectations are? Just any way to frame growth beyond 2027?

Sure. Look, I think as far as volume growth, we have -- literally, we have increased at a higher rate of growth than the underlying base. And I don't think that picture changes going forward. I got into more hot water back in 2025 when I talked about the 10% CAGR through the end of the decade. And everyone remembers that, including my CFO, who's literally just -- he's just carrying now.

But I think the short answer is the building blocks that we said there were there. And obviously, 2025, I recognize was literally, we had to look our wounds and we had some bumps along the away. And we sold EPIC, which obviously changed things. But interestingly enough, the $988 million is what we ultimately reported. If we end up at $1.1 billion, that's an 11% growth rate.

And my expectation is, look, 2027, I think, is a step change relative to what anyone expects. And I think going forward, that 10% CAGR growth, all those building blocks to that foundation for that CAGR are still in place, if not actually more pronounced today than they were back then. So I think we feel really good about what we are seeing in front of us.

And I think the opportunity set presenting, as I said, New Mexico, abundant number of opportunities. Texas, there's a lot of opportunities. And what we really like, Trevor and commercial team are working on it is Woodford, there's some really good, really, really exciting development potential down there.

And I think we're seeing the ability to harvest both -- and that pretty much is reflective of the fact we have such a unique system. We're in the south, we're in the north. And we've got an area -- a capture area that is more expansive than most, and we're able to obviously capture that and obviously provide, we think, a premium service and a premium netback on the way that we structure our contracts.

Our next question comes from the line of Jeremy Tonet from JPMorgan Securities.

Go into 2027, if we could a little bit here. Appreciating there's a lot of variables and not providing guidance at this point. But given, I guess, the pieces you laid out there, should we expect growth to be kind of ratable across the year? Or is it more front-end or back-end loaded? Just trying to get a sense.

I think ratable. As I said, think about the earlier comments. You've got a big pull forward into the very beginning of the year, you got to pull forward into the middle of the year. That's where you're going to start to see. So I think ratable is a good way to frame it at this point. You and I don't control the drill bit, but I think that's certainly based on drilling plans and turn-in-line forecast, that's how we're -- that's what's being shown and presented to us.

Got it. That's helpful. And then I just wanted to dial in, I guess, on the balance sheet and capital allocation as you laid out there. It seems like leverage could be trending lower and especially going into next year as this growth materializes. And just wondering, I guess, how that impacts your thought process for overall?

Thanks, Jeremy. It's Trevor. It's a good question. So we exited the third quarter at 3.7x leverage, which is below the midpoint of our 3.5 to 4x target range. We still have a target of 3.5x or lower. If you take the implied fourth quarter EBITDA guide and you were to annualize it off of expected net debt, you're below our target of 3.5x at the end of this year.

And so we're really, really pleased with where leverage has trended throughout the year and its trajectory into 2027. It definitely does open up the playbook for how you think about capital allocation and the potential, I'd say, to be more offensive with how you think about capital allocation.

The counter to that is we are in an environment right now where things are quite competitive, specifically speaking about the inorganic side. We've been evaluating all of these deals, trying to find ways to make them work, but we've come up short -- that doesn't mean that I don't think that we're not going to be successful on a go-forward basis. But what I would just say is that we're in a different environment in 2026 than we were back in 2024, we were quite active.

We made 3 acquisitions in 2024, just a different time period than where we are today. So -- but you're right. I mean, with leverage improving materially, it definitely increases our flexibility, but just TBD as to what we do with that flexibility.

That's helpful. And I might have missed it, but I guess, how would you think about rank ordering repurchases?

Look, repurchases have always been part of the mix. We have a $500 million program where we have utilized about 40% of it. We were, again, quite active back in the middle of 2025 and very similar to how we think about capital deployment and allocation.

We make a move, we move swiftly. We built a position back in 2025. We're quite pleased with that position. And it definitely could come back into the fold, but I would say that it's going to be not necessarily ratable, like you can't necessarily plug in into your model x million dollars of repurchase, but it's certainly part of how we think about accelerating capital returns to shareholders and also how we just generally think about it, right, in lieu of acquiring new assets, one way is to acquire ourselves.

That's how we thought about it in 2025, and there's been no changes there. So we still have that program that we can utilize.

Our last question comes from the line of Saumya Jain from UBS.

So Phase I expands ECCC's capacity to roughly 225 and you also upsized Kings Landing II to 380. So how will ECCC's expansion profile in the coming year shift to support this additional North to South volume when Kings Landing II comes online? And what specific volume or pricing threshold in Waha would trigger an FID potentially for a Phase II expansion of the pipeline?

Thanks for the question. It's Trevor. So interestingly, with what we've seen down south, ECCC was originally contemplated to provide more processing connectivity to the north, especially while we knew that we were going to be in a period of about 24 months between FID and in service of the next cryo at the Kings Landing complex. That certainly is true today. We are flowing on ECCC north to south.

However, as Kings Landing II comes online, that's a 380 a day cryo. That will increase -- effectively double the processing capacity that we have of north. And so there's going to be a period of time where actually we're going to be moving volumes from the south up to the north because that system is getting quite filled. And so that's one of the also added benefits of ECCC is it provides a lot of flexibility with how we think about these large processing expansions -- and our peers are FIDing 250 to 400 a day cryo. So it's an industry standard.

But for us, let's not miss the fact that that's a 15% increase in total processing capacity across our system. That's a big expansion for us. And so with ECCC, it will -- again, we're really pleased with that 225 of north to south or south to north volumes. And again, that will help us balance out the system as we're building cryos up north and then potential to build a cryo down in Texas as our next cryo.

It's Jamie. What I think is most interesting with this is a lot of our Eddy County volume is sweet and obviously, we have a lot of sweet in the South. So that sweet gas has the ability to go to a sour plant, which obviously Kings Landing will be entirely sour.

We can have sweet gas at a sour plant. We can't take sour gas and take it to a sweet plant. And so what we have on the western side of our footprint allows us this potential to move gas up, move gas down. And that, I think, is hydraulically and from an engineering standpoint, that is truly something that allows us to optimize and fully utilize our full processing capacity stack for the entire business.

I think we -- operator, I think we're done or any more questions?

Next Yes. There are no further questions at this time. I will now hand the call back over to Jamie Welch for closing remarks.

Thank you, everyone, for your time this morning. I know there was a lot to get through, so we appreciate it on a busy day, and we look forward to seeing you all soon. Thank you very much.

This concludes today's conference call. Thank you for your participation. You may now disconnect.

Hello, everyone. Thank you for joining us, and welcome to the Kinetik's Second Quarter 2026 Results. [Operator Instructions]

I will now hand the conference over to Alex Durkee, Head of Investor Relations. Please go ahead.

Good morning, and welcome to Kinetik's Second Quarter 2026 Earnings Conference Call. Our speakers today are Jamie Welch, President and Chief Executive Officer; and Trevor Howard, Senior Vice President and Chief Financial Officer.

As a reminder, today's discussion will include forward-looking statements. Please refer to our SEC filings for a discussion of the risks that could cause actual results to differ materially. We will also reference certain non-GAAP financial measures. Reconciliations can be found in our earnings materials and on our website.

With that, I will turn the call over to Jamie.

Thank you, Alex. Good morning, everyone. Kinetik delivered the strongest financial results in our history. Our performance was driven by exceptional operational execution, strong system performance and a supportive commodity price environment. I'm proud of our team whose focus, discipline and commitment to excellence continue to drive these results.

Accordingly, we are updating our full year 2026 adjusted EBITDA guidance upwards by $70 million at the midpoint or 7%, reflecting the strong first half performance and confidence in the outlook for the remainder of the year. Trevor will discuss the key drivers behind our guidance update in more detail shortly.

The confidence embedded in our revised outlook is reinforced by what we're seeing across our footprint today. Customer development activity continues to build. Commercial momentum is the strongest it has been since our inception in 2022, and our team is executing at a very high level. Combined with improved market conditions, these trends position us well for a strong finish to 2026 and tremendous follow-through into 2027. We are seeing broad-based momentum across our integrated gathering, processing and downstream platform.

Conditions across the Permian continue to improve as Waha pricing has recovered from the extreme dislocations experienced for the first 5-plus months of this year, driving a step change in producer curtailments since mid-June. At the same time, the more constructive crude oil environment continues to support attractive development economics, and we're seeing a continuation of customer activity pull forward across our footprint with some of that benefit to materialize in the second half of 2026. Reflecting these trends, Permian rig count has increased 8% since February, with over 60% of that growth coming from the Delaware Basin.

Against this backdrop of accelerating activity and growing producer demand, we continue to proactively position our system for the next phase of development. In May, we reached FID on Kings Landing II. The message from customers has been crystal clear. Incremental sour gas treating and processing capacity is needed to support their development plans. As such, we elected to increase the processing capacity of KLII by 50% to 300 million cubic feet per day. Since announcing the expansion, we have already purchased cryo processing, amine and residue compression equipment, and the project is now expected to be completed in mid-2028 earlier than previously communicated. On completion, Delaware North sour gas processing capacity will exceed 700 million cubic feet per day and Kinetik's total system-wide gas processing capacity will surpass 2.7 billion cubic feet per day.

Importantly, we're already looking beyond KLII. This week, Kinetik's Board authorized procurement of long lead equipment for the next stage of processing capacity expansion, proactively aligning our supply chain with accelerating customer demand. This positions us to manage equipment lead times, preserve development flexibility and efficiently support the next phase of growth on our system. We have also sanctioned the commencement of work on expanding the capacity of ECCC. Our willingness to materially reinvest in our business reflects not only the visibility we have into customer development plans but also our conviction in the long-term growth outlook for the Permian Basin.

To that end, the market continues to recognize the Permian's critical role in meeting future U.S. natural gas demand growth. With LNG exports, power generation and data center development driving incremental consumption, the question has increasingly become where the gas will come from and how we will reach end markets. The Permian remains uniquely positioned to answer that call with more than 11 billion cubic feet per day of new basin egress capacity that has been sanctioned through 2029.

Against this backdrop, Kinetik's integrated business is becoming increasingly valuable to customers seeking both reliable flow assurance and premium priced market access. During the quarter, we executed several commercial agreements that further strengthen the value proposition of our Permian to Gulf Coast platform while expanding market access and optionality for both existing and future customers.

First, we secured incremental firm residue gas access to Gulf Coast markets beginning in 2027, providing customers with enhanced flow assurance and premium netback pricing. We also signed new residue gas and NGL transportation agreements supporting our Delaware North processing complexes, increasing operational flexibility and securing critical downstream capacity as activity and volumes continue to grow across our New Mexico business. These agreements are excellent examples of our broader strategy to reduce our customers' exposure to in-basin pricing volatility by expanding access to premium end markets.

More importantly, they reflect our differentiated approach to commercializing the value of Kinetik's integrated platform. Rather than competing solely on GMP services, we continue to leverage our downstream assets and market connectivity to deliver a comprehensive solution for producer customers.

Operationally, our team executed very well during the quarter. A significant driver of our record results was sustained system-wide performance, reflecting both the strength of our operations and our continued focus on optimization opportunities across the system. The ECCC pipeline has been placed into service, officially establishing that north to south connection across the western portion of our system between Eddy and Culberson counties. Rich gas volumes on the pipeline are expected to increase throughout the balance of the year as Kings Landing reaches full utilization.

At Kings Landing, the acid gas injection and sour conversion project continues to advance with drilling operations well underway and Phase 1 remains on schedule for in-service by year-end. In Delaware South, Diamond Volt, our 40-megawatt behind-the-meter power generation project at Diamond Cryo continues construction progress with in-service anticipated in the second quarter of 2027.

Now before I hand the call over to Trevor, I want to underscore how confident we are in Kinetik's position and long-term trajectory. The strategic investments we have made across our platform are delivering exactly as intended, strengthening our financial performance, expanding our commercial opportunity set and enhancing the value we provide to customers. We are seeing the benefits of our integrated model come through in a meaningful way. Our assets are performing well. Our team is executing with discipline and the momentum across the business continues to accelerate.

As customer activity builds and the need for reliable connected infrastructure becomes even more critical, Kinetik is uniquely positioned to deliver. We exited the second quarter with stronger earnings power, greater visibility and a clear line of sight to continued value creation in 2027 and beyond.

And with that, I will turn the call over to Trevor.

As Jamie highlighted, the second quarter was a record one for Kinetik. We reported adjusted EBITDA of $281 million, distributable cash flow of $195 million and free cash flow of $105 million, reflecting strong execution across the business.

Within Midstream Logistics, adjusted EBITDA increased 35% year-over-year to $205 million. Processed natural gas volumes were 1.74 billion cubic feet per day, flat year-over-year despite an estimated 250 million cubic feet per day of Waha price-related curtailments. Results benefited from strong system operating performance, improved NGL recoveries and condensate yields, optimization opportunities and lastly, favorable commodity prices and spreads.

Our Pipeline Transportation segment generated adjusted EBITDA of $83 million, down year-over-year, primarily due to the divestiture of our equity interest in EPIC Crude. This was partially offset by year-over-year outperformance at Permian Highway Pipeline, supported by lower fuel costs and higher gross margin and better-than-expected throughput volumes at Shin Oak. At quarter end, leverage was 3.8x and liquidity exceeded $1 billion, and we expect leverage to decline further by year-end, even with our elevated capital program. Importantly, we continue to operate comfortably within our targeted leverage range of 3.5 to 4x while maintaining substantial flexibility to fund attractive growth projects and return capital to shareholders.

Turning to guidance. We are substantially increasing our full year 2026 adjusted EBITDA outlook to a range of $1.04 billion to $1.1 billion. At the midpoint, the revised outlook represents a 7% increase relative to our original guidance issued in February and approximately 15% growth year-over-year on a pro forma basis for the EPIC Crude divestiture.

There are 4 primary drivers supporting our revised outlook. First, our volume expectations have improved meaningfully since our May outlook. At the time, we expected low- to mid-single-digit volume growth due to the elevated Waha price-related curtailments. Since then, Waha pricing has normalized, curtailed volumes have returned to production more quickly than anticipated and customer activity has continued to accelerate. As a result, we now expect mid- to high single-digit volume growth year-over-year. Average curtailments are expected to decline to approximately 25 million cubic feet per day for the balance of 2026. And we expect to exit the year approaching 2.2 billion cubic feet per day of processed gas volumes with no curtailments assumed in the fourth quarter.

Second, commodity prices remain favorable to our outlook. Updated guidance assumes forward market pricing as of July 28 and reflects a nearly 30% increase in WTI pricing and a nearly 20% increase in liquids pricing relative to commodity assumptions used in our original guidance in February. While Waha natural gas pricing remains well below our original assumptions, that impact has been offset by the significant Gulf Coast marketing gains realized in the first half of the year. However, as Waha pricing has improved and basis differentials have tightened, we expect those marketing benefits to moderate in the second half of the year and be replaced by the return of curtailed volumes. We remain substantially hedged through the year-end at the top end of our targeted range of 40% to 80%, opportunistically adding incremental hedge protection in the second quarter and aligning with our rolling 12-month and 24-month targets.

Third, operational execution across the system continues to exceed our expectations. Strong plant and compression run times, higher NGL recoveries, increased condensate yields and continued optimization efforts across our footprint are expected to provide ongoing benefit through the balance of the year.

And lastly, our Pipeline Transportation segment continues to outperform our original forecast, supported by stronger basin activity, higher throughput volumes and healthy margins across our pipeline businesses. As it relates to quarterly cadence, we expect adjusted EBITDA to be between $260 million to $270 million in the third quarter and $270 million and $280 million in the fourth quarter of this year, supported by increasing customer volumes across the system and ECCC utilization.

We are also increasing our 2026 capital expenditures guidance, including maintenance capital to approximately $560 million. The increase is primarily driven by several initiatives that we believe represent highly attractive investments for our shareholders. These include Kings Landing II, additional optimization projects across our footprint, the purchase of compression equipment to address elongating lead times and an increasingly stretched supply chain, the acceleration of certain growth capital investments supporting customer development plans in late 2026 and early 2027 and right-of-way procurement for an expansion of ECCC.

We have also started procuring long lead equipment for our next cryo beyond Kings Landing II, which positions us to better manage supply chain risk and preserve timing flexibility for our continued expected processing expansion.

Turning to capital allocation. Our growth-oriented philosophy remains unchanged. We continue to prioritize investing in high-return organic growth opportunities that strengthen our integrated platform and expand the earnings power of the business. The increase to our capital expenditures guidance reflects the quality of the opportunities in front of us today and our conviction in our long-term outlook. Simply put, we believe elevated reinvestment today builds the earnings base that funds growing returns tomorrow.

Alongside this reinvestment, we remain committed to a growing and well-covered dividend. In late July, we paid our second quarter dividend of $0.81 per share with dividend coverage improving to approximately 1.5x, up from 1.2x for full year 2025. We expect coverage to continue to strengthen through the second half of the year and into 2027, supporting sustained dividend growth consistent with the framework we have publicly outlined.

Operator, we can now open the line for questions.

[Operator Instructions] Your first question is from the line of Spiro Dounis with Citi.

I want to start on the processing capacity first. Just looking at that 2.2 Bcf a day exit rate, it seems like you'll be knocking on the door of capacity and maybe even exceed it in 2027. Jamie, I think you referred to the flow-through there as tremendous. And so until KLII comes online, it seems like you might have to look into some offload. So curious, are we thinking about that dynamic right as we head into '27 and maybe just any plans to deal with those excess volumes here?

Yes, Spiro, I think it is certainly something that we look at and analyze on a weekly basis with the ops engineering team, particularly with Matt Wall. We've got some projects underway where we're looking to rebuild center blocks of existing 200 a day cryos to continue to increase and upsize capacity. I think there's more to come on those particular topics. So the idea comes in a couple of different flavors.

One is what's the most you can get out of the existing footprint and system capacity today? What could we do to improve it? Two, what offloads on an interim basis could we start to consider as we get further and further into 2026 and into 2027, that would basically bridge us. So both dynamics are in play and both dynamics are being analyzed. We are obviously quite excited that KLII looks like it's going to be earlier than what we had previously communicated. That's a good thing.

I don't -- you shouldn't -- I mean, when we're looking to shave time, we're looking at months and weeks. We're not looking at moving it many months or a year or anything like that. And obviously, to that vein, we decided that, look, given the -- on the supply chain side, given what we're seeing, it was important for us to get ahead of the next cryo. And whether that's in New Mexico or whether that's in Texas and the location of that is TBD, we want to be ready, and we want to make sure that we are -- we don't have any timing impediments to basically execute on that plan.

Got it. That's helpful color. Second question here, maybe just focusing on the operational outperformance. You called it out in the materials and the remarks here, and it appears to actually be a sizable contributor to some of the beat and raise going forward. So can you just talk about what's suddenly driving this outperformance? Was this a specific initiative you guys have undertaken? Perhaps if possible, maybe put some numbers on it for us. And as we think about the go forward here, is this something you expect to build on? Or are we kind of see most of it already?

I think, Spiro, I want to maybe just take you back. When we first bought -- acquired Durango and talked about the acquisition, we identified that it was a system that needed remedial capital. It had a lot of -- there was reliability issues, there were operational issues. There was -- it was an aged system that needed a refresh. We have spent millions and millions on a concerted effort where we have replaced pipe, we have repaired pipe. We have repaired facilities. We have upgraded facilities. We have improved measurement. We have, therefore, improved reliability and run times. Our FLNU, basically fuel lost and unaccounted for reductions, have been significant. Our recoveries have improvements have been significant. This was all part of the grand plan. It's taken us 2 years to get here, which is not surprising. We obviously had Kings Landing in the interim, but it just took time.

And now we look at the operational performance, and we are seeing less of a marked dislocation between the operational recoveries and performance of the north versus what we have in the south. We have undertaken -- yes, we do a lot of low-pressure gathering and processing, as you well know. We're probably one of the biggest, if not almost the biggest on the low-pressure side in the Delaware Basin. So compressor stations and the usage of fuel at the compressor stations, whether that's lean gas, which was a big initiative that Trevor and Ross, together with Matt initiated several years ago, where we converted our stations from rich to lean, so we were not burning NGLs, was an initiative that we rolled out in New Mexico. And so we are doing things that we -- that at the end of the day, continue to optimize our operational performance and improve. Obviously, we see the overall system benefits and you see them reflected in our financials.

Your next question comes from the line of Jeremy Tonet with JPMorgan Securities LLC.

Just wanted to drill in a little bit more on these points, if we could. Just wondering if you could tell us where volumes are currently in that 2.2 that you see, is that a 4Q average? Or is that like a December 31 number? Just trying to get the trajectory, I guess, of volumes from today to year-end as that propels into '27.

Yes, sure. Thanks, Jeremy. It's Trevor. If you go to Page 6, you can look at the far right bar chart. It is a 4Q 2026 average is at approximately 2.2 Bcf a day. And then on the second part of your question, second quarter 2026 processed gas volumes was 1.74 Bcf a day. We did disclose that there was approximately 250 million cubic feet a day of curtailments on average in the quarter. And then on a go-forward basis, we estimate that there's 25 million cubic feet a day of curtailments for the second half of the year on average. So if you take 225 million cubic feet a day of return volumes that were previously shut in in that 2Q 2026 number, that puts you at around 1.95, 1.96 Bcf a day is how I would bridge that question.

Got it. And just coming back to system performance, great to see everything coming together there. And just wondering, I guess, how do you think effective capacity for the plant stands right now versus kind of nameplate as we think about this volume growth if it's going double digits into next year, just how we think about that?

Well, Jeremy, it's Jamie. So I think as far as nameplate, down south, most of our existing cryos are 200 a day cryos, particularly for East Toyah, Pecos and even Pecos Bend. We obviously did the expansion at Diamond. And so we get close to almost 720 million cubic feet a day out of those 3 cryos. So said another way, it's like 240 would be max that you could get. But you'd probably be sacrificing recoveries if you're sort of running it at that very top end.

I think we are looking at additional residue recompression, center block rebuilds, which should be able to get you between close to 220, 230, I think, is probably somewhere within that frame. I think Matt is on. He can sort of jump in here for the 200 a day cryos. And as you know, we have -- of those, we have 5 in the south. So if you can get 20 to 30, you're getting 100 to 150 or said another way, at the top end, 75% of another 200 a day cryo. Matt, do you want to jump in there?

Yes. No, I think all that's fair. In general, I'd say through residue compression upgrades and then expand or intersection changeouts, we can see an incremental 10% to 15% above nameplate on any of the cryos down south.

So that helps us, I think, Jeremy, in the context of what we're doing. And obviously, we've been spending -- we obviously are focusing also on the north of what we can get out of those plants, Dagger Draw, Maljamar, obviously, Kings Landing will be running. We expect it will be at around 220 with the additional residue recompression. So I think we are maxing out our processing capacity. And as I said earlier on in response to Spiro's question, we're also analyzing the probable potential need for offloads in the short term sometime in '27 in advance of having Kings Landing 2 come on in '28.

And Jeremy, just to clear one thing out, the 2.4 Bcf a day of processing capacity that we disclosed, that's effective processing capacity as of today.

Got it. And one last quick one as it relates to produced water. I think it looks like it might be heading down a little bit. Just wondering what's happening with the water side. It seems like water is increasing overall for the basin. Just wondering, is this a mix shift in wells or anything else at play here?

I think at the end of the day, it's as simple as we've got some large new projects and timing is impacting it. So I think it's more of a temporary situation. But I think there are some fairly large developments on the water side, which will see volumes rise pretty materially.

Your next question is from the line of Theresa Chen with Barclays.

Going back to the macro side of things, can you elaborate on your earlier comments on customer activity and tell us what you're observing in terms of producer behaviors at this point, commensurate with your updated comments on curtailments and volumetric guidance as well as touch on the accelerated spend related to supporting customer developments into late 2026 contributing to higher CapEx guidance. Are there specific areas you're observing this more than others? And as we exit 2026, any early thoughts on the directional trajectory of customer activity for 2027?

Theresa, thanks. Let me see if I can break it down. As far as -- let me deal with the macro. We're 6 months into a conflict with Iran. We're still -- literally, we live day by day in the context of whether there's resolution and sort of the return to more normal times or whether there's not. We see -- obviously, we see constructive overall commodity pricing. $75 is a very different place than $60 or something in the low -- in the high 50s, which obviously was a time that we had to endure during 2025. So we continue to see a lot of the smaller producers that have literally looked to capitalize, and we said this in our first quarter remarks back in May, that they have really accelerated activities. And so they are smaller maybe in size, but there are more of them and particularly both in the north and sort of areas in and around the south, we've seen that activity continue.

As it relates to the pull forwards, we have -- there were a lot of fairly large developments which were on the schedule and on the turn-in-line plans from our various producers that were pulled forward from mid-2027 or later in 2027 to early 2027 or in a couple of cases into late 2026. And so that activity is what obviously has created the need for additional well connects. I go back to the point of so much of what we do, absent only a few customers is all low pressure. So we are literally building to the CTB. And therefore, for us, we're spending with some of these pads, you've got not just well connects, but we have compressor stations, and we have other things and other ancillary equipment that we -- ancillary infrastructure that needs to be built.

So that's really the genesis and the and the reason for, obviously, some of the increase in the capital that we saw and we're moving up from the top end of our range, which we told you when we FID KLII that we were at the top end of $510 million. We're now -- we're saying approximately $560 million. So I think we see a lot of activity right now. And I think, particularly in New Mexico, that is remaining very much supreme as far as just the amount of activity and how the depth of it. And even in the South, we're seeing, obviously, with a more constructive Waha and the ability for people to use Gulf Coast egress, we're seeing increasing activity down south as well. So we got the best of both worlds.

Yes. I'd like to just emphasize Jamie's last point there, the CapEx pull forward that you see in 2026 for development that is later this year and then first quarter, second quarter of 2027 that we have to prepare for. That's really large-cap independent E&Ps in Delaware South. We are seeing an acceleration of activity in New Mexico as well. But that incremental capital that you're seeing in 2026 really is the Delaware South system. And that's just part of the reason -- part of the reason for that is just timing for new wells to be planned for and get connected to the system. In Texas, it's 1 to 2 quarters faster than what you see up in New Mexico. So we are planning in New Mexico right now for second half of '27. Prospects look very good. But as it relates to 2026 CapEx, really, that's a Delaware South phenomenon.

That's very helpful. And then maybe on the cost side of things, can you update us and remind us where you are in terms of incremental savings related to your NGL recontracting activities? And also on the residue side of things, I believe you had entered into some short-term contracts back in November. Can you remind us when that rolls off and how that bridges into your recent capacity contracted beginning in 2027?

Okay. On the NGL side, I think we said in May and certainly in February, we have a pre-existing flexible solution as we see some of our Delaware South contracts, 2 of which roll off over the remaining passage of this year. It gives us a lot of flexibility. The rates are obviously market and quite attractive. Most recently, obviously, we've been tackling the Delaware North. We announced that we just signed a contract that gives us a lot of flexibility as it relates to our 3 complexes up there, Dagger Draw, Maljamar, Kings Landing, very attractive rate. We're very happy with the flexibility it provides us going forward. So that's -- we feel like that's another box that's checked on our list of -- on our to-do list.

As it relates to residue, what we contracted for last year doesn't roll off, that remains as it is and will going into going forward. And obviously, that sort of stages into, I think, into 2028 when we've got, I think it's IGA, which comes on as the pipeline, and we have some capacity on that.

As it relates to the newest capacity additions, they are supplemental because, obviously, you can imagine the first 5.5 months of this year has been a crisis for anyone having to sell gas at Waha on such a negative basis. And therefore, everyone wanted to get out, and they still do. And I think, honestly, while there's a reprieve right now, which we're very glad for, and we hope that that continues, and we continue to see more egress capacity on the horizon that I think what we're all potentially missing is the amount of gas that we continue to see building from all producers across the Permian Basin is just this rising tide that doesn't seem to abate and will not abate. And therefore, the prudent action for any producer is to have at least some or all of your residue pricing at Gulf Coast or a premium end market versus the whiplash that you get at Waha. So we have been supplementing our capacity stack, and we will continue to do so because we have a -- I would say we continue to see that need from our customers.

Your next question is from the line of Jackie Koletas with Goldman Sachs.

I think you touched on it a little bit, but just talking on guidance, you recently raised full year reflecting a strong first half performance. As we look into the second half of the year, you outlined the transition where moderate marketing gains will be offset by the return of curtailed volumes. How do you think about the incremental upside from here to expectations? What could bring you maybe closer to the upper end of that new guidance range and where you may be most conservative here?

Jackie, it's Jamie. I'll start this, and Trevor is penciling out already his thoughts. But I think, look, there's so many facets to our business. There's a macro facet, and I give Trevor and Jared a lot of credit because they did really look to capitalize on some of the incremental commodity price outperformance across the balance of this year with their hedging over the course of the second quarter. But there's still a portion that moves. Obviously, Waha, are we going to stay at this level at sort of $1.90 or $2? Is it going to actually -- is it going to return to the doldrums as we get into maintenance season come October, November, obviously, when we have a lot of the existing egress pipes go through their scheduled maintenance periods. How do we think about overall outperformance in the context of our underlying producers and their forecast and how we risk them?

Like there are so many aspects that go into our business that I think we are -- we try to navigate what we think is prudent and proper as we think about timing of pads, how a producer will bring a pad on, what the risking assumption versus their type curve that they will give us. So I don't know, Trevor, where you want to take this, but I think it's like we've given you the best available information that is -- that we have today. We are cognizant that we've obviously had a very solid first half, and we're very pleased with the results. And we want to continue to build on that as we go forward through the balance of this year.

Yes. The only -- the other thing that I would add is, to Jamie's point, look, we received customer development plans and customer volume forecast, which we risk appropriately to the extent that our customers accelerate timing relative to our expectations and wells outperform, that is a source of outperformance that we've seen this year. I'd say another big one is the operational and system outperformance year-to-date so far. To the extent that continues, that is a source of upside risk to the forecast.

That's very clear. I appreciate the color. And just as a follow-up, you touched a lot on the strong commercial progress and accelerated customer growth, leading to that incremental spending in '26. As you head into '27, how are you thinking about the run rate capital in the near term in order to meet that customer demand in comparison to your previous commentary of $200 million to $400 million run rate?

I think, Jackie, I've seen it from a lot of our peers, and I would very much echo the following sentiment, which is we are seeing a new, I would say, prudent paradigm on capital investment, and that really was the core of our revised capital allocation philosophy and that we saw the need -- literally, we had to press the advantage. We had to make the investments. The overall investment returns were so compelling that we saw a need to continue.

So what that means is this sort of level that we've got $560 million, obviously, I think, for this year, we've, I think, been very clear in that $500 million, $600 million range is very comfortable for us. And I think as we look forward, the nice thing about it is we can modify as needed based on activity levels. It's -- that's -- you've got -- that's 2 cryos, right, in the context of how we think, 1 cryo every 18 months kind of thing. That's how we sort of, I think, forecast it, at least on a longer-term basis right now based on the plans and forecast that we see.

Your next question comes from the line of Keith Stanley with Wolfe Research.

I wanted to start and follow up on the volume outlook. So if you take the Q2 volumes and add back the curtailments, you're pretty close to 2 Bcf a day. So that's about 10% growth by the fourth quarter. Can you say where volumes are today on the system? And just how much visibility and confidence you have on that ramp, which is pretty steep into year-end?

Yes, sure. Keith, I'd point you to one of my earlier responses, which is we had 1.74 Bcf a day of processed gas volumes in the second quarter. If you normalize for the return of shut-ins of 250 million cubic feet a day and then back out the 25 million cubic feet a day of shut-ins that we expect in the second half of the year, we're in and around 1.96 Bcf a day as a kind of a bridge to where we are in the third quarter right now.

As it relates to the second part of your question and getting from that 1.96 to approximately 2.2 Bcf a day, we have a ton of visibility into that. We've been planning for several large packages in New Mexico for the better part of 12 to 18 months now that are starting to flow back. So we feel quite confident in being able to achieve that run rate in the fourth quarter of this year.

Great. And then, Trevor, I wanted to follow up on what you said earlier that if the optimization and system performance improvement continues that that would be an upside to your forecast and guidance. Is there any reason to think that you wouldn't continue to benefit from the performance improvements you've made in the system? Or is the uplift not as large if commodities are lower? Just how you're thinking about that and how it's baked into the outlook at this point?

Yes, that's a good question. I'll hit one of your last parts of the question, which is the unhedged portion, right? Obviously, because we have volumes that are out or exceeding expectations, those volumes that we received in the first half of this year have been unhedged. So there is a margin component there. So I just wanted to hit that first. But as it relates to the $40 million to $50 million of system performance in the full year of 2026, which is part of that green wedge that you see on Page 6, a substantial portion of that has been realized year-to-date. There is a portion of that in the second half that we are forecasting, but not necessarily taking the outperformance that we've seen and then running with that on a go-forward basis.

As it relates to the last part of your question in terms of where we could miss and why that would actually go away. I'll actually hand that off to Matt, our COO, so he can hit on that and what are some of the operational items as to why we wouldn't experience the current run rate recoveries that we've been seeing thus far.

Yes. Probably an important thing to just talk on the ops performance is specifically as it relates to Delaware North, as Jamie mentioned, we did a lot of maintenance projects all the way across the system to improve recoveries, performance, et cetera. I think for the most part, we've gotten to a point where we're going to plateau, but I don't know that we'll see large gains from where we sit at today. But I don't expect us to go backwards. I mean I think that we'll continue to do what we've done to kind of get to the point where we're at on system performance and hold it there. But for instance, on recoveries for heavier components, I mean, we've got to a point where I think is normal, and I don't see us being able to go do projects to get incremental recovery barrels on heavy components.

I was going to say, Matt, you and I talked about sort of more on the heavy end. I think we've hit the optimization. We may still have some opportunities on the lighter end of the NGL barrel. But again, that's going to just take some more time and more focus and emphasis. It's a constant refinement of a recipe for a chef. That's probably the way to describe it. It's never going to be perfect to first. You're going to refine it, refine it to make it better. And I think that's what we're going to see, Keith, going forward.

Your next question comes from the line of Julien Dumoulin-Smith with Jefferies.

This is actually Patrick [ Berta ] on the line for Julian today. There's been a lot of detail there that was very helpful. I just wanted to clarify maybe a little bit of the language. I think I've got in my notes here that your dividend policy was based around having that coverage ratio get back up to 1.6. And I think in your opening remarks, you said that you got to 1.5 and it could grow from there. Is there likely to be any change in your dividend policy from that in the context of your comments about your comfort with the $500 million to $600 million CapEx program a year and the free cash flow you got going there?

Patrick, this is Jamie Welch. So the short answer is no. I mean we're at $0.81. We said we would grow at 3% to 5% per year on a base case and that once we got to 1.6% and above, we would start to see it grow in line with overall cash flow growth, which obviously would mean it's an outsized increase. So there's no risk whatsoever in the context of the base nor a different approach at all relative to that even with a -- we have, I think, assumed internally that the capital plan is sort of as we're seeing right now.

Yes. The other thing that I would add to that is I think the bigger governor for us, at least in how we think about dividend growth is probably leverage. And given the fact that -- and as it relates to how CapEx influences that. But leverage -- our leverage range is 3.5 to 4 turns. Our target is 3.5 turns -- last quarter, we're at 3.8. So we're right in the middle of our stated range. Even with elevated capital budgets, I think in my prepared remarks, we talked about how leverage is expected to continue to decrease throughout the balance of this year. So very comfortable with where leverage sits, very comfortable with where dividend coverage sits and no changes to our return of capital levers that we've outlined on Page 9.

Great. And then a second question was a little bit about further out along that CapEx time line. I think it was Theresa's question maybe. I think you talked about the ECCC will roughly double in size and before you said it wouldn't take too much CapEx to expand that and you've got your new cryos that you mentioned. Are we looking at a 2-year program with that elevated CapEx program? Or are you looking even further out keeping it that high?

Look, we're looking further out. I mean, like I had mentioned, New Mexico for the pads that we're bringing on right now, we've been planning for 12 to 18 months. We're starting planning for -- or we've already made significant headway on planning for the second half of 2027 program and then also starting into 2028. So we are really planning our business for 2028 and beyond. Kings Landing II is expected to come online summer of 2028. We announced that we have initiated procurement of long lead items and equipment for the next cryo thereafter, which if you just take the timing between when we announced the FID of Kings Landing and it's in service, it's around 24 months.

So from here, we're already planning for additional processing capacity in the second half of 2028 or thereafter. So we -- with that -- in Jamie's comments, in and around 1 cryo per year at $500 million to $600 million of total capital, growth capital is about $400 million to $500 million per annum at those levels. You add a cryo to that, there's potential upside risk to that CapEx. But to answer your question, we're just -- we're looking at '27, we're looking at 2028, and we're already looking at 2029. And to the extent that the macro holds and producer customers continue to keep showing us these volume forecasts that require additional processing capacity, you should expect CapEx to remain in and around these levels so long as we're building one cryo at a time.

Your next question comes from the line of Saumya Jain with UBS.

There are no further questions at this time. I will now turn the call back to Jamie Welch for closing remarks.

Thank you very much, everybody, for your time this morning. We wish you a great end of the summer. We'll be seeing you again on the circuit and with our next quarterly call in November.

This concludes today's call. Thank you for attending. You may now disconnect.

Hello, everyone. Thank you for joining us, and welcome to the Kinetik First Quarter 2026 Results. [Operator Instructions]

I will now hand the conference over to Alex Durkee, Head of Investor Relations. Please go ahead.

Good morning, and welcome to Kinetik's First Quarter 2026 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 in attendance for this morning's call.

As a reminder, today's discussion will include forward-looking statements that are subject to risks and uncertainties that may cause actual results to differ materially. For a discussion of these factors, please refer to our SEC filings. We will also reference certain non-GAAP financial measures. Reconciliations to the most comparable GAAP measures can be found in our earnings materials and on our website.

With that, I will turn the call over to Jamie.

Thank you, Alex. Good morning, everyone. Kinetik delivered record earnings in the first quarter. This reflects key execution across our three core pillars, commercial, operations and financial.

Before walking through each in more detail, I wanted to briefly touch on recent geopolitical developments. The global macroeconomic landscape has shifted meaningfully since reporting fourth quarter 2025 results. While Trevor will cover the implications that we see today in more detail, we believe that Kinetik is incredibly well positioned as these dynamics continue to play out.

Commercially, our team has been highly productive. We've seen strong conversion of opportunities into new and amended agreements across both Texas and New Mexico. Over the past few months, we've added new customers across our gas, crude and water service offerings while continuing to advance our strategy of revising commercial terms and extending legacy Durango contracts.

During the quarter, we completed a significant contract amendment with a large existing customer in New Mexico that expands the original dedicated acreage by roughly 25%. It consolidates multiple agreements into a single contract and extends terms through 2039.

As a result, approximately 75% of legacy Durango gas processing volumes have now been amended over the past four months. Collectively, these new and amended contracts extend terms into the mid- and late 2030s, increase margin, expand dedicated acreage, broaden services rendered, provide downstream control of plant products and reinforce long-term visibility across our New Mexico system.

As we've said before, the message from customers has been clear. incremental sour gas treating and processing capacity is a necessity to support their development plans in New Mexico. Our strong runtime performance at Kings Landing and continued progress on the sour conversion project, combined with the recent contract amendments and new agreements have created strong commercial momentum in support of potentially advancing a processing capacity expansion at Kings Landing complex.

We also continue to pursue highly capital-efficient power generation-related opportunities. We signed a zero CapEx interconnection with Pecos Power, connecting our Delaware Link residue gas pipeline to the Pecos Power plant in Reeves County. Combined with the CPV Basin Ranch interconnection announced late last year, we have again demonstrated a fee-based template for monetizing our existing footprint as Permian power generation demand grows.

On the operations front, field operations executed at a high level this quarter, delivering reliable performance across the system while maintaining a strong focus on safety. We have also made solid progress across our capital projects in the quarter. We are nearing completion now of the ECCC pipeline within service later this quarter.

At Kings Landing, we received all required approvals from the BLM and the NMOCD, allowing us to proceed with the AGI and sour gas conversion project for the full 20 million cubic feet per day of total asset gas or TAG capacity. All long lead materials have been ordered, construction is underway, and we plan to spud the first acid gas injection well this summer.

Once complete, the project will enable us to handle elevated H2S and CO2 levels across all three Delaware North processing complexes, providing total operational TAG capacity of 26.5 million cubic feet per day and permitted capacity in excess of 31 million cubic feet per day.

Phase 1 of the sour conversion for Kings Landing remains on track for in-service by year-end 2026 and meaningfully enhances the long-term value of our New Mexico business. In Delaware South, we advanced our 40-megawatt behind-the-meter power generation solution at Diamond Cryo. Turbine equipment has started to arrive on site and engineering, procurement and permitting work is well underway.

And financially, we remain highly focused on executing on our priorities, including leveraging data and technology to drive efficiency across our business. In February, we began our pilot program with Palantir and have been encouraged by early results, which are reinforcing more data-driven execution across the organization.

Now at the same time, our finance and operations teams are progressing on our operating cost reduction initiatives. Importantly, operating and G&A expenses are tracking in line with our budget estimates. And through our efforts so far, the teams have identified additional efficiencies that optimize our cost structure for 2027 and thereafter.

At the end of last year, we secured more residue gas transport capacity to the Gulf Coast, which provided financial insulation to the pronounced price-related production shut-ins we had seen and expect for much of 2026. As new Gulf Coast takeaway capacity comes online and hub differentials tighten into 2027, Kinetik remains well positioned as curtailed volumes return and gross margin normalizes reducing the contribution from this spread-driven financial offset.

We remain extremely vigilant about managing our medium- and long-term Gulf Coast transportation capacity portfolio. Not only is it important for our customers to receive Gulf Coast hub pricing, but also critical for growing with new customers. We recently secured additional Gulf Coast pricing exposure starting in 2028. And we also have our European LNG price contract with INEOS starting in early 2027.

Since 2018, we have shown that we think outside the box and believe it is one of our corporate core strengths to creatively find premium pricing solutions for our customers' natural gas. Stepping back, the contracts we have signed, the commercial opportunities we are pursuing and the takeaway we have secured all extend Kinetik's earnings durability well into the next decade.

The near-term gas price environment is a cycle to manage through, not a thesis to revisit. We are managing through it from a position of strength and our confidence in the multiyear plan has only increased over the passage of the last 90 days.

And with that, I'll turn it over to Trevor.

Thank you, Jamie. First quarter adjusted EBITDA of $251 million was a quarterly record and came in above the high end of the range that I outlined during our fourth quarter earnings conference call.

Distributable cash flow totaled $181 million and free cash flow was $101 million. The Midstream Logistics segment delivered a record $179 million of adjusted EBITDA, up 12% year-over-year, essentially on flat volumes. The result is a direct payoff from the Gulf Coast takeaway capacity that we contracted late last year. Spread-based marketing gains have more than offset approximately 170 million cubic feet per day of Waha price-related production shut-ins in the quarter, converting what would have been a volume headwind into a margin tailwind.

In addition to the wider basis spread outperformance relative to our internal expectations was also driven by stronger-than-expected system operating performance that yielded more condensate and NGL recoveries, higher fee-based margins, stronger commodity prices and slightly lower unit operating costs than budgeted.

Our Pipeline Transportation segment generated $78 million of adjusted EBITDA, down year-over-year, reflecting the EPIC Crude divestiture that closed on October 31 and lower throughput volumes on Shin Oak.

Turning to our updated outlook. As Jamie noted earlier, the macroeconomic environment has shifted meaningfully. Higher commodity prices in response to the conflict in the Middle East have driven improvements in the forward pricing curve, implying stronger commodity margins relative to the underlying assumptions in our guidance.

While we have seen activity pull forwards with certain customers, primarily pertaining to 2027 activity, overall producer behavior remains disciplined. In stark contrast, we have experienced a significantly more challenged price environment at the Waha Hub. In March and April, the gas daily average price at Waha was negative $4.81.

Given the push and pull dynamic of higher crude prices and a highly oversupplied local natural gas market, a few of the assumptions underpinning our guidance have changed. First, processed natural gas volumes expectations. In February, we called for high single-digit percentage volume growth year-over-year in 2026, inclusive of 100 million cubic feet per day of curtailments from gas price-sensitive customers.

Actual production shut-ins to date have been materially higher than that expectation. We now forecast low to mid-single-digit percentage growth in processed gas volumes year-over-year, which reflects approximately 220 million cubic feet per day of curtailments on average for 2026.

At current processed gas volumes of approximately 1.8 Bcf per day, the incremental 120 million cubic feet per day of curtailments represents a decline of more than 6 percentage points relative to our original growth expectations. In conclusion, the reduction in volume growth expectations is driven by our assumptions on price-related shut-ins, which are temporary in nature.

Second, financially offsetting the impact from the Waha price-related production shut-ins are the wider natural gas hub price differentials. To date, the Waha to Houston Ship Channel spread has been wider than assumed in guidance, enabling stronger-than-expected marketing gains. We have approximately 50% of our transport spread exposure hedged in 2026. And as a reminder, our spread hedging tends to be lower during the spring and fall pipeline maintenance seasons and higher during the summer and winter months.

And third, commodity prices have moved higher since the onset of the conflict in the Middle East. While ethane has remained relatively flat, the NGL composite and propane have increased over 20% since the February 13 strip used in our guidance assumptions and WTI is up over 30%.

We have capitalized on higher prices with incremental hedges. Specifically, we estimate our equity volume exposures are approximately 75% hedged for propane and butane volumes and approximately 85% hedged for crude and C5+ volumes. Marking to market our commodity price exposure, we estimate an uplift of approximately $20 million to full year 2026 adjusted EBITDA at current forward pricing, excluding our Gulf Coast marketing spread.

We are affirming our 2026 adjusted EBITDA guidance range of $950 million to $1.05 billion. Relative to our underlying assumptions in our February guidance, we expect to benefit from improved commodity margin and Gulf Coast marketing opportunities, partially offset by lower volume expectations associated with the temporary price-related shut-ins.

With respect to earnings growth cadence for the remainder of 2026, I would reiterate my comments from our fourth quarter call. We expected the first and second quarter results to be in the $230 million to $240 million range and the third -- and fourth quarter results to be in the $260 million to $270 million range.

Given our first quarter results exceeded that expectation, we are tracking ahead of plan. We continue to expect quarterly performance to generally align with the cadence originally outlined for the balance of the year. We continue to expect 2026 capital expenditures guidance in the range of $450 million to $510 million. CapEx, including growth and maintenance, was $91 million in the first quarter. As we look to the balance of the year, we currently anticipate the remaining spend to be pretty evenly weighted across quarters.

Now turning to the balance sheet. We ended the quarter with ample revolver capacity and leverage of 3.9x, which was within our targeted range. Our healthy balance sheet, combined with our cash flow profile provides the flexibility to fund our growth program without compromising our return of capital to our shareholders.

Looking ahead, the pace and scale of incremental residue gas takeaway capacity continues to reshape the long-term outlook for the Permian. More than 5 billion cubic feet per day of new capacity is expected to be in service by early 2027, with an additional 6 billion cubic feet per day anticipated across 2028 and 2029. This structural shift has reinforced a constructive view on long-term Permian gas growth.

Combined with the direct feedback from our customers, our confidence in the durability of our multiyear plan continues to strengthen. Execution in the near term remains critical to sustaining that trajectory, and we remain focused on consistently delivering across our three priorities, disciplined commercial conversion, reliable operational execution and conservative financial stewardship.

And with that, we can open the line for questions.

[Operator Instructions] Your first question comes from Michael Blum with Wells Fargo.

I wanted to ask about the Durango agreements that you amended and extended here. How do we think about the incremental EBITDA contribution for '26 and beyond? And with these new agreements, does this change at all the mix of your contract portfolio between fee versus POP at keep-whole or just your overall commodity exposure?

Yes. Thanks, Michael, for the question. This is Trevor. In terms of 2026, I would call it -- I think we've characterized it in the past as modest uplift, so 1% to 2% of the overall base business. So it's a nice uplift, but it really sets the stage for investing in the field and then also investing in Kings Landing further with the sour conversion and then the potential processing expansion by pushing out the duration and term of those agreements.

And it also does -- or it also has removed a portion of commodity within the business. When we acquired Durango, the system was about 60% fee, 40% commodity. And through these restructurings and amended and restated agreements, we've taken that fee-based percentage up, not quite like our business down south where that's an 85% to 90% fee margin business, but we are closing the gap there.

Got it. And then I wanted to ask on this Pecos Power deal. I guess the question is, how do we think about returns for a project like this? And do you see other opportunities in the basin to sort of replicate this? Because obviously, that is another way to sort of deal with Waha is to find more in-basin demand for gas.

Michael, it's Jamie. As far as the returns, there's no capital. So it's infinite in the context. These are -- we're seeing a lot of new gas-fired power generation located in and around West Texas. The footprint of our system is such that we have a lot of connectivity.

We have the ability to provide residue natural gas to these new power generation plants. And we've got a very active dialogue with a number of them. That's how we see our sort of role. You're correct. We look at it much the same way you pointed out, which is this is a little bit of self-help for Waha on the basis of creating incremental demand. So we will continue to capitalize on it. And from our vantage point, it's just a nice incremental base of fee revenue.

Michael, this is Kris. As Jamie alluded to, it's an earnings opportunity not only to sell residue gas transportation, but a lot of these power companies want hourly services. So to the extent we can provide that flexibility, that's additional margin. So again, we're in conversations with these parties right now, but it's future upside that we're working with.

Your next question comes from Spiro Dounis with Citi.

I want to start with Kings Landing 2. So you announced the new dedications. You talked about growth accelerating into early '27. And Trevor, you just mentioned that a lot of this sort of sets the stage for an expansion. So just kind of curious how close you are. I think originally, the potential FID was a 2026 line item. Just want to get a sense on where that stands or if there's maybe even a capital-light option you could pursue first.

Spiro, it's Jamie. I think as far as Kings Landing 2 is concerned, yes, we have been actively engaged in commercializing that project opportunity for some time. We have knocked down incremental steps along the way, which we think brings us closer and closer to the end point of finally being able to FID that particular plant.

So I think we are getting close. And I think the overall level of activity that we continue to see reinforces our belief in just the prospects and opportunity that we find that presented in New Mexico. So I think we're pretty excited.

In the interim, as you know, ECCC will come into service. Effectively, it will be sort of in a month from now. And we'll obviously be able to start taking incremental what we would say, sweet New Mexico volumes down south for processing capacity. And we'll continue to look at the level of activity just more broadly in New Mexico, which remains very robust.

Spiro, this is Trevor. On your last comment just about the capital-light option, really, ECCC was that option, right? Because Delaware North was on an island and not connected to our Delaware South system, we would -- Kings Landing 1 is going to get filled this year. And so we would have already have a Kings Landing 2 in service by the end of this year in order to take incremental gas.

And so we've taken that measure with ECCC and being able to utilize processing capacity in other parts of our system. And then also there's just more markets and more optionality down in Texas.

Got it. Understood. Second question, maybe just going back to the 2026 EBITDA cadence. Trevor, you kind of walked through it a little bit, but could you just maybe give us a little bit more detail on the drivers for the back half of the year ramp? Obviously, you've got some ramping assets, but Waha likely isn't improving until maybe mid-summer. There's some indications you Brining could come online by that time frame and help provide some relief.

Curious how you're thinking about when the marketing gains flip to curtailments coming back online and volumes being the bigger driver. It sounds like that's what you're counting on for the back half of the year. I just want to make sure that's right.

Well, I think Trevor will answer this, but I think, Spiro, what we've announced with the incremental expectation for curtailment is that we foresee a continuing period of challenge for Waha. And in -- for the sake of being conservative, we wanted to communicate that the overall level of curtailments were actually higher than we anticipated, obviously, in our original guidance.

And more importantly, it's deferred revenue. right? That volume will show up. And in the meantime, we found a bunch of money in the form of these marketing revenues that have obviously been able to, in fact, not only ensure that we've met our financial guidance, but obviously, I think there's a net windfall here for our overall stakeholders because you've got money for marketing and you're going to have deferred revenue coming from the return of production.

I'll also make just kind of piggybacking off of Jamie's comments it makes it easier to grow in 2027 because the PDP base starting off are off with in January '27 will be higher. Again, Jamie's comments are right, it's deferred revenue. PDP will be higher entering into 2027. So, it really sets up '27 well. And in the meantime, we talked ad nauseam about this, but the strategy that we've employed with the Gulf Coast marketing hedge as an offset to curtailments has been effective.

But with respect to the ramp in the back half, of the year. I'd reiterate my comments in the prepared remarks where no changes to our second through fourth quarter earnings cadence, $2.30 to $2.40 in the second quarter and $260 million to $270 million each quarter in the second half of this year.

What I would say is that what's driving that is actually not a return of shut-in volume. We're expecting shut-ins to persist through the balance of the year and really resume in December of this year. When you look at the forward spreads, Waha is negative up until October. So, we've taken maybe a little bit of conservatism here just given the fact that that's a maintenance period. And so, we wanted to ensure that we're out of the maintenance season before expecting volumes to return.

Really, to answer your question, what is driving this, we have a very summer-heavy development program. And we have a handful of big packages of gas that are coming online across the system and particularly in New Mexico. And then we also -- that's really in the third quarter. And then in the fourth quarter, we have some Texas packages that are real needle movers for gas volume growth. And then come December, that's when you have the resumption of curtailed volumes and then Gulf Coast marketing margins declining.

Spiro, it's sort of interesting that we sit here on May 7, and we've only had Waha being in positive territory. In other words, greater than zero for 13 days. Six days were attributed to Winter Storm Fern. So, if you excluded Winter Storm Fern, seven days, and we're now in the fifth month of the year.

So it is -- I mean, we are dealing with unprecedented volatility. It makes it -- I know that there are some elements of frustration in the context of dealing with the level of volume growth, and we've seen some of that come out in the commentary. But put yourself in our shoes, we are dealing with things that candidly, even at the beginning of this year, we thought that 2026 would be the tale of two halves. But if you're seeing negative pricing for Waha going into October, that is something that is actually truly hard to fathom.

One more piggyback comment after Jamie, Spiro. But in terms of the volume revision lower in our year-over-year volume guidance, as you saw, we increased our curtailments by 120 million cubic feet a day on average for the full year. That's about 6 percentage points to our overall gas process volumes. And so we went from high single digits year-over-year to low to mid-single digits year-over-year, and that is solely attributable to the increase in curtailments.

Your next question comes from Brandon Bingham from Scotiabank.

I wanted to maybe go back to the setup into next year, if possible, all the egress capacity coming online at the end of the year into next year. What is your sense in discussions with producer customers that have higher in-basin pricing sensitivity about the appetite to maybe accelerate development? Is there a potential slug of, call it, pent-up supply beyond the expected curtailments as prices normalize?

Brandon, it's Jamie. So as prices normalize, you mean gas prices or normalize in the context of Waha pricing?

Yes, yes.

Okay. Well, it's interesting because, obviously, what we tried to communicate in both the press release and the prepared remarks is we have this push-pull impact right now for 2026 of what we're seeing in activity. We are seeing some of the smaller independents. We're seeing some people pull forward packages in a matter of months, weeks.

But we're seeing a building momentum in 2027, where we estimated second half of the year, middle of the year, people are pulling forward packages into the very beginning of the year. And I think the longer we have this elevated commodity price environment, the more we are going to see, particularly from our larger public customers, I think we're going to see a lot more activity in the beginning of 2027 that they'll capitalize on that continued tailwind, if you will.

So I do think that, that's definitely going to set you up for an even better 2027. I think Trevor communicated that in his prepared remarks. But not only are we going to have the return of the PDP base, which will be even higher because of the effect of the shut-ins. But also, I think we've now got a real pull forward of a lot of activity.

Okay. Great. And then maybe just quickly, you mentioned some incremental cost optimization opportunities for '27 plus. If you could maybe just expand on those to the extent you can?

Yes, sure. I'm happy to jump in. We have -- look, we have a fair amount of just general equipment that is leased where we are operating it or where it's a true lease. And so just really looking at all of our cost structure. And I think the biggest opportunity for us is just to integrate a few things that historically we've had others operate for us or have some kind of capital lease. And that's the majority of what we're seeing, and they're very capitally efficient quick payback projects for us.

And then we are -- as Jamie commented on, we're on the early onsets of really, I'd say, transforming from a data perspective, how we look at our cost structure and optimizing there, and that's more of the building the framework and the foundation for 2026 and start to see those benefits in 2027. But in 2026, the immediate is buying equipment and services that we've outsourced.

Your next question comes from Gabe Daoud with Truist.

Jamie, I was hoping maybe you could just get some thoughts around adding more Gulf Coast exposure in the '28 to '30 period. Just looking at the strip, obviously, with all the egress coming on, Waha should improve and experience better days ahead, but just curious around maybe the rationale on the longer-term exposure there.

Yes, Gabe, thanks for the question. Yes, it's an interesting question to raise because we've gone from a situation where Waha was a heavily discounted price relative to ship or South Texas, and we talked about it being disadvantaged. We've now gone to a place where it is just outright negative. It's just in such a bad place.

So I think the way we think about 28 to 30 is as follows. We expect that this too shall pass, we will get out of literally the precatory of negative pricing, and that means negative absolute pricing. But it is our estimation and belief that Waha is going to remain that discounted price point relative to every other gas nodal market price in and around Texas.

And therefore, the need if you want premium pricing will remain Gulf Coast for export. They are your two options. And so securing incremental Gulf Coast supply is going to be -- remain critically important. Likewise, trying to ensure and actually contract for incremental export and LNG opportunities is going to -- is something that we're also very much focused on.

We start our INEOS contract beginning of next year, which we're looking forward to. So I think that, look, there's a -- we will get out of this negative pricing paradigm, which is obviously quite -- which was making it extremely difficult and volatile for all of us, but it will still remain a heavily discounted price point relative to other options. And so we're going to continue focusing on the premium options and how we can secure more of it for our customers going forward because there seems like an endless demand for that from our customers.

And Gabe, this is Kris. I think the important point Jamie said was for our customers. Our customers want to get out of Waha -- the time period of '28 to '30 is important. We have renewal options on our Gulf Coast capacity in 2031, so it syncs up well with that. But again, the forward say, Waha gets better, but the last five years, the forwards have been wrong. So -- and we're seeing the gas growth out of the basin. And so it's been an important differentiator for us. So we're going to continue to get exposure in basins other than Waha.

Awesome. No, that certainly makes sense. And as you noted, the curve has been wrong in the past. So I appreciate that color. And then maybe just as a quick follow-up. Can you maybe just remind us what your fee floors are on the G&P side, just given these curtailments that you've highlighted?

I'm happy to jump in here. So we don't have fee floors in our business, Gabe.

The next question comes from Jeremy Tonet with JPMorgan Securities LLC.

Just wanted to build on some of the commentary before at the risk of getting ahead of ourselves. But it seems like '26, you're tracking ahead of expectations at this point, but don't want to lift the guide. I want to see how more unfolds. But you still have 4Q intact, as you said, as far as like gradually increasing over the course of the year. I'm wondering what that means for '27, I guess, if there's any way you can frame, I guess, how you see the momentum, what type of growth this could generate or kind of like normalized growth for the business at this point?

So Jeremy, look, I think you're right. Let's go back to your very first words. You're talking to Trevor and myself and the management team here, look, this was our second consecutive beat. It followed obviously a series of misses, which we took quite personally and actually felt like we needed to do better.

And so we are being very cautious and conservative, and it's not lost on us that we obviously had a very strong first quarter. And we are hopeful that, that will shape up for the balance of this year, and we will just sit with the guide that we've got until such time as we conclude that it makes sense for any changes.

But what is important, I think, is from transparency and communication is to understand that incremental PDP base on average, 120 million cubic feet a day is 60% of one of our existing Cryos. That's the average, right? And obviously, it peaks and troughs as it relates -- well, it peaks and declines depending upon the period. But certainly, there was already, I think, a heightened expectation for 2027, which we certainly agree with.

Obviously, we have a lot of benefits flowing through into 2027. NGL contract resets. We've got a lot of incremental benefits. We've got the first full year of our sour gas conversion project with Kings Landing. There was a lot. And with a high PDP base, accelerated activity, bringing it early into the year sets you up.

I think it's premature to think about what that means as far as actual dollars and cents or percentages of growth. But certainly, it is the sun, the moon and the stars are aligning to -- for it to be a very -- we think a very strong and positive year post 2026.

Jeremy, the other thing that I'd point you to is historically, we've guided to projects across our entire portfolio as being mid-single-digit multiples. We give a total capital number. But if you were to strip out maintenance, you're looking at $400 million to $425 million of growth last year and this year.

Looking at 2025 actuals and then adjusting out for the EPIC Crude sale, this year, you're looking at double-digit growth, and that ties to a reinvestment multiple on the growth capital that we had spent in 2025. And so just to provide you some additional color there based on prior comments that we've made.

That's helpful there. And at the risk of pushing my luck here, I was just curious, I guess, some of your peers in the basin have talked of a certain cadence that they think that processing capacity expansions might be required with their footprint, X amount -- X plants per year, what have you. Just didn't know if you had any high-level thoughts on what it might look like for Kinetik in framing it in similar terms.

Look, I think that's not -- we too take note of some of those statements from some of our competitors. I think we're probably getting to the -- on the cusp of being big enough that we can think about what that cadence may look like. I don't think we're at that point quite yet.

We'd like to sort of first get Kings Landing 2 sorted and done and behind us, and then we can think about it because we're still -- we're really still exploring the full benefits and breadth of opportunity set that exists in New Mexico. And I think that will then further reinforce the color and perspective of just exactly what processing cadence and growth needs to look like for this company going forward.

Your next question comes from John MacKay with Goldman Sachs.

Maybe we'll go back to the shut-ins. Back in October, you guys had talked about shut-ins from some oil-directed wells at all. I just wanted to check in and the shut-ins you're talking about either for first quarter or balance of the year, is that all effectively on the Alpine High side? Or are you expecting some kind of more regular oil-directed activity to be impacted as well?

You got it right in the context of the impact, impact Alpine High and more of our gas-sensitive customers. Clearly, there, we have not seen oil-directed customers shutting in.

To the contrary, some of these smaller guys, in particular, obviously, given what the current commodity price environment are looking to accelerate their level of activity. So it is a tale of two cities. Crude folks that doing cartel and backflips and those that are literally localized Waha gas-centric sellers are literally crying poverty.

Yes, absolutely. I appreciate that. That's clear. Second one for me is just going back to the general idea that you guys keep going to say we're going to see a lot more gas growth, GORs in the basin are going up. Would you be able to give us a bit of a mark-to-market on your NGL TNF re-contracting expectations? So alongside this, we'd expect NGL volumes to go up, maybe re-contracting gains might not be as high as we could have thought end of last year. Maybe just, again, mark us to market on that, if you don't mind.

Yes. No problem. John, I think we said on the call in February that actually the market was even more aggressive than we had -- than we were anticipating. And still, it is early days. And obviously, we're in this discovery phase as we've communicated. And we said we would clearly communicate to the market at the appropriate time. But I think to the contrary, I think the expectation is you will have even better net realized margins on our part than what we had previously communicated because of the environment that we find ourselves in. So, I think it's actually the antithesis of what you just -- as you just described it.

Your next question comes from Keith Stanley with Wolfe Research.

For the new packages of gas coming on in the summer that boost the second half of the year outlook, I want to confirm, those producers that are bringing on those new volumes, they have gas takeaway capacity, so they're not sensitive to what's going on with Waha?

Yes. Correct, Keith. They've got Gulf Coast transport.

Okay. Great. Second question is, I mean, you've had a good couple of quarters now on dealing with the Waha issue. How confident or how much visibility do you have that marketing gains can continue to offset curtailment losses this year? And what's the risk around that? I assume it's just if pipes you have FT on experience unexpected downtime. Just can you kind of frame how you're thinking about risks to continuing to be able to manage this year?

Sure. So obviously, from a -- as it relates to the overall dynamic, we have multiple FT arrangements on multiple pipelines. I think the overall reliability that we've seen continues to remain high. And obviously, it would have far reaching consequences if there were unexpected issues. We're not anticipating any. They have a very regular cadence of maintenance, both in the fall and in the spring. And that's obviously communicated very clearly to the shippers.

So as far as managing is concerned, we've been looking at the spread differential between Waha and Houston Ship. We obviously have some hedges in place. We've talked about that. They very much mirror or map the expected capacity profile. So we see more dislocation in Waha in the spring and in the fall during maintenance seasons when there is curtailment of capacity, when pipes do come down for days or maybe a week.

And I think we've been able to manage it. We feel pretty confident that we're going to be able to manage it. We've managed it now through the first quarter. We've managed it through -- certainly through April, May as well. So I do think that, look, we're starting to find our sea legs as far as managing this exposure, even though it is as volatile as one sort of could potentially possibly believe. But I think Trevor and the team have done a really good job.

Keith, I'd also jump in and just say that, look, I think part of the risk that we have is that we go and test new lows. I think that this company has done a very nice job in managing what are our risks and which customers are more sensitive as you move from positive territory to minus $1 to $2 Waha, then the next tranche being $2 to $6 negative Waha. And then like we saw for a few days in April and March and then also in October of last year, where you start to see $8, $9, almost $10 negative Waha.

I think the risk, just being totally candid, is do you go and touch new lows that we haven't seen of minus $15 per MMBtu. And I think just given the setup of Hugh Brinston starting to have some deliveries in the third quarter, Blackcomb coming online in the fourth quarter, Hugh Brinson reaching full in service, GCX coming online this summer. I think the risk of us touching new lows is quite low.

But we've also done a really nice job. The commercial team has done a nice job of playing offense in this particular situation and learning from the feedback that we're seeing from our customers and migrating the portfolio to primarily Gulf Coast sales is important and a long-term strategy of ours, and that will help insulate us from the shut-ins that we've seen. And a lot of wood to chop there, but the team has done a really nice job initially, and that's been demonstrated over the last two quarters of performance.

Your next question comes from Julien Dumoulin-Smith with Jefferies.

It's Rob on for Julian. Just one for me. I think you alluded to in your prepared remarks being a bit less hedged to -- in a positive sense during the spring. Waha has been even more discounted in April and May. Any reason you wouldn't expect to perform as you did in 1Q, if not better in the second quarter as we think about maybe that tail to have you alluded to, Jamie?

Rob, thanks for the question. Look, I think let's not get ahead of ourselves. We obviously feel very confident and very good about where we are. Your statement is correct that obviously, April and May have been also fairly negative from a Waha pricing standpoint. So I think we'll take each day and each month as we find it. And I think we continue to understand that we're trying to build upon our financial base and outperform.

Your next question comes from Saumya Jain with UBS.

So as you keep your 2026 CapEx guide, what sorts of growth opportunities are you looking at in New Mexico? Would that be more on the AGI facilities on the sour gas side or maybe infrastructure investments to capture more gas residue? I guess, could you sort of detail what sorts of infrastructure investments are also needed on the gas residue side to expand that opportunity?

Sure. So this is Jamie Welch. I think as far as the infrastructure and the capital is concerned in New Mexico, 70% of our budget is allocated to New Mexico versus Texas. That's the starting point. A lot of it obviously is related to -- as we think about New Mexico, the AGI South conversion project being one of the larger ones and the completion of ECCC, the pipeline. You've got some long lead items in relation to Kings Landing 2.

I think on the residue side, we don't -- we've got connectivity already to the existing pipeline operators up there, Transwestern, El Paso, we'll have a connection to -- we will have other connections going forward to other outlets. So that's not huge dollars from our vantage point.

So I think, look, that's all encapsulated within the CapEx that we gave and we've got listed in our prepared materials. So I think it's -- if I was going to think about dollars, it's $10 million, $20 million sort of that quantum versus the overall $480 million to the midpoint for our guidance.

Okay. And then could you comment on any discussions you might have had with customers on technologies increasing recovery in the Permian? And if you've seen any notable differences from that already in the Delaware Basin?

Saumya , this is Kris. We've seen the efficiencies. I think that's showed in production data and from at least our public customers and discussing in their calls. A lot of them are reticent to share any sort of competitive advantage they have because it's part of how they optimize their costs. But we are seeing an increase in -- or a decrease in days drilled and things like that. So there's been a trend of improved technologies over time, but nothing specific to any certain customer.

We have reached the end of the Q&A session. I will now turn the call back to Jamie Welch for closing remarks.

Thank you, everyone, for your time this morning. We look forward to seeing you in a few weeks at EIC, and we wish everyone a great day.

This concludes today's call. Thank you for attending. You may now disconnect.

Hello, everyone, and thank you for joining the Kinetik Fourth Quarter 2025 Results. My name is Claire, and I will be coordinating your call today. [Operator Instructions] I will now hand over to Alex Durkee from Kinetik Holdings to begin. Please go ahead.

Good morning, and welcome to Kinetik's Fourth Quarter and Full Year 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 in attendance for this morning's call.

As a reminder, today's discussion will include forward-looking statements that are subject to risks and uncertainties that may cause actual results to differ materially. For a discussion of these factors, please refer to our SEC filings. We will also reference certain non-GAAP financial measures. Reconciliations to the most comparable GAAP measures can be found in our earnings materials and on our website.

With that, I will turn the call over to Jamie.

Thank you, Alex. Good morning, everyone. 2025 was a challenging year for the energy industry in Kinetik. Commodity price volatility, macroeconomic uncertainty, tempered customer development activity and inflationary pressures tested our business. And so our financial results underperformed expectations.

But it was also a year of important strategic progress, progress that strengthened our core business, deepened customer alignment and positioned us for a bright future. Our team is keenly aware that 2026 is our rebuilding year, a year to reestablish credibility through consistent execution, disciplined capital allocation and transparent communication.

Despite the challenging operating conditions, we still managed to deliver year-over-year EBITDA growth and executed on several foundational initiatives. We closed the bolt-on acquisition of the Barilla Draw gathering assets, enhancing our Delaware South footprint and expanding our systems capture area.

We achieved full commercial in-service at Kings Landing, a multiyear strategic build that doubled our processing capacity in Delaware North. Kings Landing is performing exceptionally well with a 99.8% run time, strong ethane recoveries and reliable performance even through the recent Winter Storm Fern.

This reliability is critical as inlet volumes rise and eventually sour gas content increases. We also reached FID on the Kings Landing sour gas conversion project that is expected in service by year-end 2026. That project will ultimately increase our total permitted acid gas injection capacity across our Delaware North processing complexes to over 31 million cubic feet per day, enabling us to meaningfully scale sour gas handling across the Northern Delaware Basin.

Completion of the ECCC Pipeline remains on schedule for in-service next quarter. ECCC is a critical link between Eddy and Culberson Counties and unlocks additional growth by providing Delaware North with direct access to our latent processing capacity in Delaware South. Yesterday, we announced that we reached FID on our first behind-the-meter gas-fired power generation project at the Diamond Cryo facility.

We have purchased a 40-megawatt gas turbine scheduled to arrive in West Texas during the second quarter. The project requires less than $25 million of capital, is expected to be in service in late 2026 and provides a scalable, cost-efficient power solution that can be replicated at several of our other processing facilities in Delaware South.

Continuing to execute on initiatives that reduce our operating cost structure, thereby making our existing assets more profitable and our business more competitive is a key focus for our team going forward. 2025 was also a year of meaningful commercial advancement.

We amended gas gathering and processing agreements with our 2 largest legacy Durango Midstream customers, extending terms into the mid-2030s and enhancing long-term cash flow visibility through fixed fee structures, treating fees and control of residue gas and NGLs. Importantly, these amended agreements increase expected EBITDA beginning in 2026, strengthen long-term customer alignment and position Kinetik to grow alongside these producers as development increasingly shifts towards more sour gas benches.

Our G&P agreement in Delaware South was amended to shift the residue gas price point from Waha to premium Gulf Coast markets, improving this customer's natural gas price realizations and reducing our indirect exposure to in-basin price volatility via price-related production curtailments. These types of commercial refinements underscore our focus on creating win-win outcomes that enhance system utilization and long-term value.

We also executed long-term agreements with CPV and INEOS, demonstrating our ability to create differentiated pricing solutions across power generation and international gas markets. And our commercial success has continued into this year as we're finalizing a new agreement for low and high-pressure gathering and processing services in Lea County with one of our large existing customers.

We are reminded daily that location, a low-cost structure and connectivity determine the winners in midstream. The Texas and New Mexico natural gas supply and demand forces at play today reinforce a very attractive thesis for our business. Kinetik strategically sits at the crossroads of rising low-cost natural gas supply and rapidly growing demand along the U.S. Gulf Coast, for which our system is a critical link in the energy value chain.

Permian natural gas production is expected to grow nearly 4% annually through 2030, supported by rising GORs, attractive gas-rich plays and accelerating domestic natural gas demand. Gas-to-oil ratios, especially in the Delaware, are climbing steadily as development moves into gassier zones.

Delaware Basin GORs are projected to increase nearly 70% over the next couple of decades. At the same time, highly productive gas-rich plays like the Barnett, Woodford and Alpine High are becoming increasingly attractive as producers delineate and prove out the resource and gas fundamentals improve. Permian gas takeaway capacity remains a critical component of the outlook.

The industry is bringing online approximately 5 billion cubic feet per day of incremental egress by the first quarter of next year, representing nearly 20% of current Permian natural gas production volume. While we still anticipate Waha gas price volatility during the spring and the fall pipeline maintenance seasons, takeaway gas pipeline utilization near 90% should provide pricing relief at Waha.

Additional projects like Eiger Express and Desert Southwest slated to come online in 2028 and 2029, further strengthen the Waha price relief narrative. Accelerating ERCOT power generation demand, driven largely by data centers creates substantial upside for gas-fired power generation, especially in West Texas.

Further downstream, the U.S. Gulf Coast remains the most attractive natural gas demand story globally, with LNG capacity expansions expected to increase gas demand by nearly 12 billion cubic feet per day through 2030. Before turning the call to Trevor, I'd like to reiterate that we recognize the importance of restoring investor confidence this year.

Our priorities for 2026 are clear: meet or exceed our financial estimates, tighten operating cost discipline, deliver projects on time and on budget, play offense regarding our Waha exposure. Examples include amendments of existing G&P agreements, as mentioned earlier, potentially being part of the solution for new takeaway capacity options and creative sales agreements.

And lastly, convert our commercial opportunities pipeline into long-term agreements, which would result in the FID of additional system investments at compelling multiples. We enter 2026 with momentum, a strong system and a clear mandate. While I am incredibly proud of our team's success to-date, there is a huge opportunity to meaningfully and accretively continue to grow our business. To capture that opportunity, we need to operate at a higher level in 2026. And I know we have the right people to do just that.

With that, I will turn it over to Trevor.

Thanks, Jamie. In the fourth quarter, we reported adjusted EBITDA of $252 million. We generated distributable cash flow of $152 million and free cash flow was negative $12 million. Midstream Logistics delivered $173 million of adjusted EBITDA, up 15% year-over-year, driven by gas volume growth, Gulf Coast marketing gains and a onetime operating expense benefit, partially offset by Waha price-related production shut-ins.

Pipeline Transportation generated $84 million of adjusted EBITDA, down year-over-year due to the EPIC Crude divestiture that closed on October 31. The approximately $500 million of proceeds received from the EPIC Crude sale were used to pay down borrowings at the revolving credit facility, improving liquidity and deleveraging the balance sheet, both important for our revised capital allocation framework.

Additionally, distributions from PHP were down approximately $31 million in the fourth quarter versus the third quarter due to a change in distribution policy resulting in a portion of the fourth quarter distribution being paid at the beginning of January. This change in the distribution policy has no further consequence nor is it a reflection on PHP's financial performance.

For the full year, adjusted EBITDA was $988 million, slightly above the midpoint of revised guidance. Capital expenditures were $497 million, in line with revised guidance. We repurchased $176 million of Class A common stock and exited the year at 3.8x leverage. Turning to the financial guidance issued yesterday, we expect 2026 adjusted EBITDA of $950 million to $1.05 billion.

The midpoint of $1 billion represents over 7% growth year-over-year when adjusting for the sale of EPIC Crude. Within the Midstream Logistics segment, key assumptions include high single-digit growth in processed gas volumes across the system, outpacing broader Permian production growth, approximately 100 million cubic feet per day of expected Waha price-related production shut-ins, and these are most pronounced during pipeline maintenance periods in the fall and spring.

Gas process volumes exceeding 2 billion cubic feet per day in the second half of this year, supported by ECCC in service and Kings Landing ramping to full utilization, approximately 84% of fixed fee gross profit and flat to slightly down operating expenses relative to our third quarter 2025 run rate. Since we still expect substantial volatility at Waha this year, I would like to spend a bit of time on how we approach guidance with utilization of our Gulf Coast transport capacity to offset the financial impact of anticipated production shut-ins.

We believe our guidance is appropriately risked based on the following: we saw the extent to which curtailments could impact the business in the fall of 2025 and assumed similar levels in our forecast. We are modeling strip pricing, which suggests depressed Waha pricing for most of the year, especially during the spring and fall pipeline maintenance seasons.

While we are planning for material price-related shut-ins, we are also expecting marketing contributions as a financial offset. Given the magnitude of the Waha to Gulf Coast hub natural gas price differential, we have approximately 40% of our transport spread exposure hedged.

Our 2026 adjusted EBITDA guidance also reflects the full year impact of the EPIC Crude divestiture as well as margin and volume adjustments at Shin Oak within the Pipeline Transportation segment. Moving to 2026 capital expenditures guidance. We expect $450 million to $510 million of capital expenditures with approximately 70% of capital spent in New Mexico including the ECCC pipeline, gathering investments in Eddy and Lea Counties and the Kings Landing sour gas conversion project.

Our Delaware South budget includes the behind-the-meter power generation project, regular way low-pressure gathering and compression capital to service existing agreements and a handful of optimization projects that will increase processing capacity at several of our Delaware South processing complexes. I would like to discuss our revised capital allocation framework and how we're positioning the company for long-term value creation.

Over the past year, we've shifted from a balanced all-of-the-above capital allocation model to a growth-oriented framework aligned with multiyear visibility and high-return opportunities. Our updated capital allocation framework reflects a structural opportunity to reinvest in projects that generate highly attractive rates of return and enhance our overall strategic and integrated enterprise value.

All the while, we plan to modestly increase capital returns to shareholders via annual dividend increases and remain disciplined around leverage and balance sheet resiliency. As growth projects come online and cash flow steps up, we expect to accelerate cash returns to shareholders. There are a few elements I want to highlight.

First, elevated growth capital budgets are expected, driven by high-return projects supported by our system footprint, operational reliability and long-term commercial agreements. Second, we will target leverage between 3.5x and 4x. The scale of the opportunity set requires disciplined project high grading in order for us to operate within this range, which we believe appropriately protects our company's financial health.

Third, we plan to increase the dividend annually by 3% to 5% until our dividend coverage reaches 1.6x. Upon achievement of 1.6x, dividend increases should track earnings growth. Fourth, we will pursue share repurchases opportunistically. With elevated CapEx, buybacks will naturally be lower in the near term, but over time, they will become an additional mechanism for incremental cash returns as free cash flow [indiscernible]. And finally, we will preserve balance sheet flexibility with investment-grade ratings remaining an objective, but not at the expense of alternative compelling returns.

Before we start Q&A, I would like to pass the call back to Jamie.

Thanks, Trevor. I want to briefly address recent M&A conjecture. As a reminder, we do not comment on market rumors or speculation, and we won't be doing so today. What I will reiterate is this. We operate in an industry where assets of scale, integration and durability are highly strategic.

We swim with other large players and recognize that the broader landscape is constantly evolving. Against that backdrop, our focus remains on executing our strategy and driving near- and long-term shareholder value. We are incredibly excited about what lies ahead in 2026 and beyond and believe we are well-positioned to drive multiyear growth.

And so with that, we can open the line for questions.

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

I want to start with the outlook here. Noticeable difference in tone this call from the last call. I'm just curious, what's giving you this what seems like renewed confidence as you're heading into 2026? And why are you so confident in the EBITDA range this year?

Spiro, it's Jamie. So first off, thanks for the question. Look, I think we obviously had our bumps and bruises last quarter and for 2025 we've licked our wounds, and we've basically been head down, focused on execution ever since. I think with the restructuring of the 2 large legacy Durango Midstream contracts, they were really critical to get over the finish line, and we did it.

That opens up a tremendous window of opportunity as it relates to sour gas benches and sour gas just generally for the Northern Delaware. It is also apparent that there is a lot of activity in and around the Northern Delaware that we're starting -- that has been emerging for some time, but is now really getting significant momentum. And there is probably more in-house commercial activity today than we've had for multiple years in the context of just things that are actually happening that obviously can really move the needle.

And that obviously creates the realignment and the refresh on the capital allocation strategy. The sort of the organic growth first is obviously what we see here as being sort of our critical threshold going forward. So if you hear it, I think we are genuinely excited.

And what we bring to the table in the North is a function of the following: we bring not just sour gas and the ability of sour gas treating with obviously the acid gas conversion project going on at Kings Landing, the prospect in the near-term for Kings Landing 2.

But more -- just as importantly, as we start to have folks emphasize and focus on co-development, the ability to give Gulf Coast pricing for Northern Delaware Basin customers that has been something nonexistent. And that really, I think the entire package provides a compelling proposition even at a -- in a $60 WTI price.

Got it. That's helpful. Maybe sticking on this sort of line of questioning around the outlook and looking beyond '26. I hate to be in the what have you done for me lately camp, but the dividend guidance of 3% to 5% growth to get up to 1.6x coverage does imply that you expect to be growing beyond that 3% to 5% range.

And there's quite a few things impacting you at the end of '26 that really don't benefit you until '27. So in that context, how are you thinking about growth beyond this year? How much could get unlocked by Permian gas egress coming online alone? And maybe if you just could update us on the latest thinking around NGL recontracting.

Sure. So I'll start. I'm sure Trevor will jump in. Look, a viewpoint would be as follows. We said this year is a 7% growth when you basically normalize by excluding EPIC. So same-store sales growth, 7% year-on-year for EBITDA. We have a trajectory that is on the incline over the course of this year and towards the back end of the year, the coverage ratio is right around 1.5x.

And while we won't talk specifically about 2027, we think the setup is tremendous, really tremendous. I think as far as what I would say is egress, look, 5.3 Bcf a day, I think, by the time Phase 2 of Hugh Brinson comes online, that's about almost 20% of your overall current net Permian gas production. That's a nice shot in the arm. That is a very, very constructive element.

And on top of that, obviously, following within short order because it -- this is the first time I can remember where we have follow-on egress projects already literally working through the system in construction, and that is Eiger Express and obviously, Desert Southwest. So you come into '27, into 2028, late probably fourth quarter, you think in Eiger Express in 2029, you think in Desert Southwest.

You're really going to be -- that's going to be a much more constructive situation. And I think, honestly, Spiro, I think our viewpoint is I know a lot of our customers and some of our other peers have talked about the Barnett-Woodford. I think those types of gassier zones are really going to play off the overall constructive element around Waha pricing that we start to see with this egress relief.

By the way, you did ask about NGLs. I would say on NGLs, look, in the context of this, we look -- obviously, we've got a couple of contracts that roll off this year in the Delaware South area that is obviously well known to everybody. We're very excited by what we see around us right now.

Obviously, you've got 5 or 6 very active large integrated NGL players aggressively looking for market share and obviously being very aggressive around rates. So I think our expectation is probably more on the conservative side relative to what actually may occur. But obviously, more to come over the course of this year and as we look to get things tied down.

Our next question comes from John Mackay from Goldman Sachs.

Why don't we pick up on a couple of these things. I wanted to talk about the kind of ex curtailment volume guidance or volume number you disclosed for fourth quarter. Could you talk about kind of how much of those curtailed volumes have come back? What are you kind of specifically expecting for '26? And maybe just a little more color on the trajectory there.

Yes. Thanks for the question, John. This is Trevor. What I would say is that we had 170 million cubic feet a day on average of curtailments in the fourth quarter. We alluded to really 3 contract amendments. We had 1 in Delaware South, and we had 2 at Delaware North. We estimate that, that has brought back online about 50 million cubic feet a day when you normalize for those 2 agreements.

And so really the preponderance of the remaining shut-ins pertains to our gas-focused customer, which is Apache in the Alpine High area. With where Waha prices are right now, I think it's safe to assume that we are at a level that does not make sense to continue to flow. So what we have assumed in our forecast is on average for calendar year 2026, about 100 million cubic feet a day of curtailments. I'm glad that you did bring that up.

We did mention that volumes across our entire system in 2026 are up high single digits year-on-year. What's interesting about that is if you just were to bifurcate it between Delaware North and Delaware South, we're at about 35% year-on-year in Delaware North, which makes sense just given the fact that we had a massive increase with Kings Landing coming online at double processing capacity in the third quarter of 2025.

But interestingly, and I think it's just not widely talked about by the investment community is Delaware South has grown at 3%. But if you were to normalize for the curtailments, it'd be growing at 10%, which is above Permian Basin average volume expectations.

So kind of echoing on comments from Jamie on the previous question, we're incredibly excited about what we're seeing both at Delaware North and Delaware South, and we think that the forecast that we have is appropriately risked the current macro that we anticipate really through the balance of the year.

When you look at the Waha forwards, we're not expecting things really to get better until -- or the market is not expecting things to get better until December. And it's effectively what we have done with our forecast as we look at 2026.

I appreciate the color, Trevor. Can we ask second one, just on Kings Landing 2. I think the line from you guys is continuing to finalize commercial negotiations. Can you tell us a little bit more about that? Maybe how much of that factors into the AGI capacity ramping up? Just walk us through some of those moving pieces.

Yes, sure. So John, it's Jamie. As it relates to KL2, we continue to progress. I would say the restructurings that were done of the 2 largest legacy Durango Midstream customers is a significant positive. There are some other activities. As I said, the amount of commercial discussions and activity going on right now is probably the greatest, most significant it's been for several years.

And we're anticipating that we will obviously land a number of those planes. With that being the case, I would expect that at some point over the course of 2026, we will have an announcement on KL2. We have already factored into our construction capital budget that we actually have included an amount on the basis that we're anticipating that we will actually FID it.

So there would be no revision to the capital budget if we did. I would say the overall AGI capacity, first phase comes online by the end of this year. If you recall, I think we've talked about this before, there is a requirement that you have a companion well. So you drill an AGI well, but in New Mexico, you need to have a companion well.

So that companion well obviously will give us incremental capacity over and above what we have with our first AGI well, which will add, I believe it is another 4 million cubic feet a day of capacity, and then we will step up ultimately up to 24 and then we're at 31 in total, as shown, I think, in the materials.

Our next question comes from Gabe Moreen from Mizuho.

Could I ask a little bit about the commodity sensitivity first around, I think you mentioned getting more fee-based with these renegotiations at Durango. But it looks like from the pie chart, the fixed fee versus commodity hasn't really moved that much. So I'm just wondering if that moves kind of in the future and maybe out years?

And the second would just be around some of the kind of creative solutions, Jamie, that you referenced on Permian egress. Given customers' exposure to Gulf Coast pricing, I'm just wondering about your confidence level in terms of hedging your own exposure to that, whether that's PHP or some of the capacity, I think that you had mentioned that you lined up last quarter going forward?

Thanks for the question. This is Trevor. On your first one relating to just the percentage of overall gross margin being contributed from commodity. What I would say is that it remains elevated relative to what you would expect with the conversion of really one primary contract from commodity to fixed fee, and that's because just the marketing contributions associated with our Gulf Coast transport hedge.

We expect that in 2026 and then in 2027 thereafter, we expect that to effectively go away. And so therefore, we include that in our commodity that you see on Page 9 of our earnings slides. But again, that should reduce back to a lower level come 2027.

Gabe, this is Kris. On the kind of creative commercial structuring. I mean, we've talked about this for a couple of quarters. We've been able to use the Gulf Coast capacity as a lever and a commercial tool to get new business. And as Jamie alluded to, it was important in restructuring these contracts. A lot of these customers need to get out of Waha, and we provide a good solution for that.

And looking forward, it's obviously been a good hedge for us for the shut-ins as we showed in the fourth quarter, and that will continue to be the case. We're optimistic that Waha is relieved with the 5 Bcf coming online and the additional pipelines. But in the event it's not, we're setting ourselves up to win with our capacity position to capitalize that on future opportunities as well.

And maybe if I could just follow up on the 40-megawatt behind the meter project. Can you talk about whether you at all are shopping some of that power to potential third parties and you're viewing that all -- or you're viewing that as being all used for your own account in terms of getting kind of the returns you need? And I think, Jamie, you mentioned potentially pursuing others. Can you just talk about the decision points about pursuing that timeline, capital involved, et cetera?

Sure. So Gabe, the 40 megawatts is for self-consumption. So it is for -- or everything is for Diamond. We have the ability to actually -- we can convert it to a combined cycle facility and therefore, increase it by up to 60 megawatts. And if we decided to do that, we would do that because we saw a significant opportunity just given the price of power, and we could look to sell that power back into the grid.

None of that's factored into our numbers. We're just looking at it on the most [indiscernible] and just plain vanilla terms, which is $25 million of capital. There's a -- it's a very attractive project, very low multiple sort of investment. And we've been talking about this a while. It was good to get it over the finish line, and we look to having it in service by the end of the year.

Our next question comes from Michael Blum from Wells Fargo.

I'm wondering can you provide a little more detail on what's in growth CapEx number, particularly the -- what you're calling rich gas opportunities in New Mexico optimization and field CapEx? And should we think of that as kind of normal course recurring items that we should expect to see in growth CapEx going forward?

Yes. Thanks for the question, Michael. It's Trevor. If you go to Page 10 of our earnings slides, we try to lay it out a little bit differently this year just to help address one of the questions you had noted, which was what's more lumpy in nature and then what's regular way business. And if you look at the right pie chart, we laid it out as steel and maintenance, right?

So low-pressure gathering, compression and then maintenance that we have to do every single year. That's about 50% of our total $480 million capital backlog. So about $240 million is what I would say is regular way capital going forward. Now -- it's not necessarily -- that's not to be viewed as a maintenance number in terms of holding things flat. We have volumes that are expected to grow 8% per annum.

So as you think about like a true maintenance number, it would be lower than that. And then on the trunk line side, we do have a few completions of trunk lines in Delaware North and Delaware South that provide a little bit more connectivity to the system that are not recurring in nature. We also have the ECCC, which we will complete in the second quarter of this year.

And then on the facility side, that is primarily the Kings Landing sour conversion. And then we also have a few optimization projects down at Delaware South that increased processing capacity at several of our facilities. Again, that's necessary to facilitate the growth that we see on the system, but more so viewed as, I'd say, onetime in nature, not necessarily ongoing.

And the BTM project.

Great. That's very helpful. Appreciate that. And then I guess maybe go back to an earlier point as we think about the cadence of EBITDA by quarter, you mentioned it's going to be kind of upward sloping. But I'm wondering if you could give us a sense of what exit rate EBITDA in Q4 could look like?

Yes. This is Trevor again. I would say that Jamie's comments earlier on just dividend coverage, just to expand on that, I think you mentioned that we would be at approximately 1.5 dividend coverage exiting the year. It's really a bit of a tale of 2 halves. If I were to just normalize the fourth quarter numbers for a few things, I'd point out that fourth quarter 2025 included about $5 million of EBITDA from EPIC Crude.

We also had an OpEx benefit. And collectively, those 2 would bring us down by about $15 million. And then we've talked about this on prior calls, Enterprise has also talked about this. But with Bahia online, we're expecting a shift in volumes from Shin Oak over to Bahia.

That's about $3 million to $4 million on a quarterly basis. So on a normalized basis, you're kind of in that $230 million to $240 million ZIP code for the first 2 quarters. And then in order to hit the full one year -- or excuse me, the full year $1 billion of EBITDA, you're at $260 million to $270 million in the third and fourth quarters.

Our next question comes from Julien Dumoulin-Smith from Jefferies.

This is Rob Mosca on for Julien. So 4Q looked pretty successful in terms of your ability to manage around Waha. Can you speak to what was different in 4Q than prior periods? And can you highlight some of the additional steps you've taken in '26 to manage around that volatility, whether it's the G&P contract restructuring or maybe even taking out capacity on third-party pipe?

Yes. Look, I would say, to answer your question, you just hit on 2 of them. We're able to secure additional Gulf Coast capacity that was critical for the fourth quarter. And then the second aspect is we've restructured or amended 3 contracts that for about 1/3 of the volumes that we saw shut-in, we view that has protected those volumes from resuming their shut-ins in 2026 and thereafter.

So we've taken necessary steps to help address a portion of the shut-in risk. What I would also say is just from an expectations perspective, taking a bit of a more heavy hand on what our belief is on curtailments. And like I had mentioned earlier, in my prepared remarks, we took basically fourth quarter 2025 shut-ins, and we rolled that forward, especially in the maintenance months in the spring and the fall.

And so I'd say that those are really the 3 items that are significant changes from prior quarters before fourth quarter 2025. And in terms of like the transport hedge being an offset for shut-ins, relative to our internal expectations, they matched effectively flat.

The additional curtailments that we saw relative to our forecast, as we mentioned in our disclosure, we were down by about 8% on volumes. But relative to the Gulf Coast marketing gains, it effectively was a nice perfect offset.

Rob, it's Jamie. Look, I would say just a couple of other things. Obviously, fourth quarter, we had the full quarter of KL, right? And that obviously is good. And KL has operated so well, really well. But even through Winter Storm Fern, it has operated fantastically. And a lot of credit goes to the operations engineering team.

I think as it relates to how we put this into 2026, you heard Trevor say 170 million cubic feet a day was our average shut-in for fourth quarter of last year. That is a hell of a lot of gas. That's almost a cryo. And that was our shut-in. And we have said, well, on average, for the full year this year, it's 100.

I would say between what we've done on the forecasting side and really, I would say, being very granular and really challenging ourselves on shut-ins, timing for developments, looking at OpEx, which we talked about last quarter, looking at controllable costs, looking at what we can do on the compression side, I think we've looked -- we have done a wholesale bottoms-up, ground-up overview of our business and come up with a forecast that we really feel is really well battle-tested.

No. Got it. That's really helpful color, guys. I appreciate it. And maybe without asking you to comment on specifics, just wondering if you could speak to how yourselves, the Board think about inbound strategic interest more broadly and how you'd expect to derive value for Kinetik shareholders from any synergies that could arise if something were to come to fruition?

Look, we are always willing to evaluate opportunities that maximize shareholder value. We've said this from day 1. There has been no change since February 22 of 2022. If someone comes in and can provide more value than we believe we can create ourselves, then we understand our fiduciary responsibilities to all of our shareholders and all of our stakeholders. Simple as that. There's nothing more, nothing less. It's really that simple.

Our next question comes from Jeremy Tonet from JPMorgan.

I was just wondering, I'm not sure how much you said specifically on the KL ramp. But just could you refresh me, I guess, where it stands now, how you see, I guess, that ramp transpiring over the course of the year given the macro dynamics you laid out there?

Yes, sure. 65%, 70% utilization. Expect the second half of this year to get to the 200 because I think we said exit around 2 Bcf a day of inlet. And our expectation is that this thing is going to ramp. So does that answer?

Yes. And just wanted to get back, I guess, towards -- if I try to think about the business growth normalized here, right? And I think as you talk about the first quarter, you talked about the fourth quarter, there's other factors in place such as shut-ins, but going from $230 million to $270 million would be something like 17% growth, and that's not normalized for factors you mentioned.

But just wondering, as you look forward, I mean, if you take a $270 million annualized for 2027, which I imagine there's upside for given the factors you laid out there, that points to something north of 7% growth. And just wondering how you think about, I guess, the normalized EBITDA growth for this business over time, granted there will be lumpy years.

Look, we have tried and I suppose, we've been more circumspect with our words. We said originally that this was a business that could grow at a 10% EBITDA CAGR. We said, listen, we obviously didn't do that in 2025 to -- sorry, 2024 to 2025. And 2026 is only 7%. But I still think the -- what we see gives us a lot of confidence around, we think, above-average growth.

Now it's so dependent on so many factors. Tell me what [indiscernible] prices are, tell me how gas prices are reacting. Tell me how much activity is going to be out of the Barnett-Woodford, out of the Penn Shale.

It really is so dependent on so many different factors. But I think our viewpoint is rather than being wedded or bound to a specific, this is the growth rate to anticipate. Our growth rate, we think, is going to be above average, and we feel very good about sort of what the line of sight between now and 2028.

Jeremy, this is Trevor. I'd just expand on that, Jamie's comments. Look, we put a target out there at the beginning of last year as we think about internally just arrows on the page, what has changed since 12 months ago.

Clearly, commodity prices are down and things have slowed in the Permian in terms of just an absolute just rig count perspective, but we are seeing longer lateral lengths, drilling efficiencies, lateral footage really is kind of holding and productivity gains are also resulting in just more volumes per pad, which really is from a capital efficiency perspective for midstream, it's actually fantastic.

So I'd say that macro, clearly, arrows on the page is down, but it does feel like we are starting to see the light at the end of the tunnel on this oversupply narrative -- and then also with respect to Waha, the cavalry is coming with nearly 11 Bcf a day that's going to be coming online over the next several years.

But part of why we are now comfortable with revising our capital allocation framework is we've been almost operating Delaware North of the Durango asset for 2 years now. And we are gaining increasing confidence in the opportunity set up there. And so as we look at it internally from 12 months ago, we're more bullish on the opportunity set across our entire business.

Down in Delaware South, we've talked about this in the past, but the deconsolidation theme continues to drive volumes on our system. I had mentioned earlier that, that system normalized growing at 10%, I think, is surprising to most folks. And then as Jamie had mentioned earlier, we're starting to see the deeper zones get tested in the South, it's no longer -- it's still very early days, and there's a lot of science work that needs to go into it.

But it's no longer things that are happening on the eastern side of the basin or a story in the Midland. We have 7 wells on the schedule in 2026 that are in the deeper zones, and they contribute a lot of gas. So if that story continues to be -- or if it continues to progress in 2027, it's very exciting. And so I'm not going to give an exact number. But again, that's just how we think about it in terms of arrows on a page.

I think, Jeremy, the one other thing I would just amplify on what Trevor said, we have been almost 2 years now running Durango. But I think most importantly, Kings Landing has been, whilst it was delayed from a timing standpoint, has been an unqualified success. Operationally, it has been exemplary.

It has given a lot of conviction and a lot of confidence to the producers up there. We FID-ed the sour gas conversion project. We have stuck to our commitments and our words to our producers. And in turn, the amount of support that we're getting is real. And that I think it is a symbiotic relationship that we have with our producers.

It's their partnerships. And this, I think, is we've held up our end of the bargain, and now we're seeing our customers come to the party and come to the fore as far as their level of activity and what we're seeing.

Our next question comes from Theresa Chen from Barclays.

Trevor, I want to go back to your comments about the Delaware South footprint. Can you elaborate on what exactly your customers are seeing or unlocking on the resource front here that may not be easily discernible outside looking in? What's driving the growth? How durable is it? Is it just the pace of deeper zone development or what has surprised you to the upside versus your original expectations?

Yes. I'll also let Kris Kindrick jump in here. But just to hit in terms of the numbers itself, the commercial team has done a great job to continue to expand our business with our customers and the northern part of the Delaware South system, which extends into New Mexico and Southern Lea County, and that needs no introduction in terms of just the rock quality and what we're seeing there.

But even further south, we've always said that the rock is great and it's good. It's just longer-dated inventory relative to what we're seeing up in New Mexico with the majors and the large cap independent E&Ps. And they've held on to it for a handful of years. We have seen deconsolidation with either asset sales or farm-ins or even just 1,280-acre units that have been picked off by some folks.

But again, we're starting to see this become more and more of a theme. I can think of 3 right now that we've had in the second half of 2025, where they are existing -- their existing dedications that are held by folks that had no plans to drill in the next few years, and they are now with operators where this is their sole focus and they're getting after it. Kris, anything to add there?

No, Theresa, this is Kris. To echo on what Trevor said, a lot of the deeper benches, as we know, are more gas focused. So a lot of that's going to be dependent on what Waha does. We have the capacity coming on into this year, next year. So a higher Waha price will provide a lot of conviction.

On the other hand, though, if it does get volatile with the additional gas in Waha gets depressed, we have the Gulf Coast capacity to couple that capacity with commercial deals. So we made the comment earlier, we want to win in both scenarios. We're going to continue to employ that strategy. So we're excited. The resource is there, and we're going to capture our share of the market.

Got it. And on the NGL recontracting front, understanding that there will be more details to come as you execute through, but with multiple contracts rolling over the next few years, 2 in this year, in particular, I believe, can you talk about the timeline of commercial discussions on this? And when would you expect to have more clarity on the economics and related cost savings?

Hard to give an exact calendar date of how this all progresses. Obviously, there's a lot of inbounds that have come to us because it's not a state secret that these contracts obviously expire. And so we are accumulating information. We're accumulating data. We're receiving inbounds and ideas and concepts.

And we'll make our decisions as we think that we've come to the right place, the right decisions for the right reasons. And so that's what we'll do. And I don't -- we really can't say it's going to happen by this date. I think that would be unrealistic. And look, we'll -- as soon as we've done something, do not worry. We will recognize that we will communicate it to the Street.

Our next question comes from Manav Gupta from UBS.

I just wanted to go back a little into the Power Solutions. I mean it looks like a very attractive project. But from our perspective, it also looks like a cost reduction initiative and something which stabilizes your operations, reduces your dependence on third-party electricity. So if you could talk a little bit about how internally it helps you out besides a very good attractive multiple.

Manav, you actually hit all of the key points. Obviously, for us, the important thing is reliability. So we need -- if we're going to self-generate, we need to have absolute assurance that we have the grid as the backup. Obviously, we realize that with Waha being challenged from a pricing standpoint, if we're able to self-generate ourselves on a highly reliable basis, then it is extremely attractive.

If we -- I mean, I'll put it in this context. It's as simple as if gas prices -- if Waha gas price is negative and we are producing electricity ourselves, you can presume your electricity cost is effectively 0 for that amount of electricity that you've just generated. It's as simple as that. And OpEx, we have -- when you think about the big items on OpEx, you really think about 3: salaries and benefits, you think about compression and you think about electricity. They are your 3 biggest components.

I said before, Manav, we really looked at salaries and benefits because, obviously, contractors also fit into that category and really try to actually be very, I would say, very discerning and very focused on trying to reduce those costs on compression, we've really looked at our compression fleet and worked out where we can optimize it.

And the third element, obviously, is evidenced by this capital project, which we're going to -- this beta test we're going to do with Diamond Cryo. We're very -- we are really excited by what it will show us and what it will tell us. And if it is as successful as we think it will be, we can replicate this across several of our facilities in the Delaware, South or Texas area.

Perfect. That's the point on negative -- please go on, please go on, sorry.

Yes. No, this is Tyler. Just to echo on to Jamie's comment there that, yes, the foundational investment thesis is exactly what Jamie had mentioned or alluded to. We got -- there was an earlier question about additional kind of upside. Because we have such a focus on operational reliability and insurance, that's kind of the first step -- but there are, as you know, lots of parties out there with a lot of electrical demand.

And so there are conversations that I do think in the future is definitely an opportunity, and that's definitely an objective potentially in the future for -- depending on how this goes. So -- and then the other sites, this is very replicatable. And then sourcing additional units is something that we feel confident in as well for those future projects.

Perfect. My quick follow-up here is, when we are talking to the upstream producers, not only are they saying Permian is the best rock, but they're also saying the recovery in Permian will rise over a period of time. And we are seeing some of the major players bring in lightweight proppants, some are bringing in these nano surfactants.

So when you talk to these upstream producers who are basically adding to a lot of technology in terms of how they're drilling for Permian, do you also somewhere agree with them that the recoveries on the Permian wells could increase as more technology comes in, and that would be a major upside for somebody like Kinetik?

Manav, this is Kris. That's a great comment, great question, and we tend to agree. You look at the history of the Permian, and we've seen well improvement performance improve over time, and that's going to continue to happen.

I mean some of our peers have made comments that they're seeing revisions higher, and that's largely in the Delaware Basin. We're seeing that as well. The opportunity set is large, the pie is large. And so Kinetik will -- just given our geographic footprint and our strategy, we'll be in a good position to capture the market there.

The one thing that I would add to Kris' comments, and it doesn't directly answer your question, but just -- I had mentioned this in some of my earlier comments is the efficiencies that we're seeing in terms of higher well density as well as days drilled coming down, that is a direct benefit to a company like Kinetik, where just the capital efficiency to go build for these particular pads has reduced from our business 5 years ago or even 10 years ago.

So that's one nice benefit to our business. It also allows for, I'd say, a little bit more visibility into our business, just given the size and the capital commitment for a 25-well pad. That's pretty significant. And so again, that requires a lot of planning in advance.

This is planning -- we're planning now in 2027, 2028 for these types of packages, which is a pretty, pretty massive step change again from the business that we had in the 2010. And then what I'd also say is not necessarily -- we don't -- we hear anecdotally from our customers on lightweight proppant and nanosurfactants, but really more so our conversations are around exploratory benches.

And that, again, is a very nice theme for a gas midstream player. What we're seeing is that gas quality issues are going to continue to increase and then gas rates on these new benches are substantially higher. So we've been on this trend for a few years now, and it does feel like it's finally converting over into wells on the system, and we're incredibly excited about it.

We currently have no further questions, and I would like to hand back to Jamie Welch for any closing remarks.

Thanks, everyone, for your time this morning. We look forward to talking to you over the course of the next several quarters. And please reach out if there are any questions.

Thank you. This now concludes today's call. Thank you all for joining. You may now disconnect your lines.

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.

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.

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.

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.

[Operator Instructions]

We will now take our first question from the line of Brandon Bingham with Scotiabank.

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.

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.

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.

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.

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.

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.

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

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.

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.

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?

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.

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

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?

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.

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?

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?

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.

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

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?

Sorry, during 2026?

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

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.

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?

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.

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?

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.

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

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?

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.

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?

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?

Yes, exactly. That's right. Exactly.

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?

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.

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

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?

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.

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?

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.

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

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?

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.

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.

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?

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.

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.

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.

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.

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