Kinetik Holdings Inc Aktie

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.

Good morning all, and thank you for joining us for the Kinetik's Second Quarter 2025 Results Call. My name is Carly, and I'll be coordinating the call today. [Operator Instructions]

I'd like to hand over to our host, Alex Durkee. The floor is yours.

Thank you. Good morning, and welcome to Kinetik's Second 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 in attendance 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.kinetik.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 will open the call to Q&A.

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

Thank you, Alex. Good morning, everyone, and thanks for joining our call today. Kinetik' second quarter results reflect our resilience and relentless focus on execution as we navigated through macroeconomic uncertainty and global geopolitical pressures. I am proud of what our team accomplished despite the noise that has continued to persist.

During the quarter, we made significant progress across our portfolio of capital growth projects. Starting with Kings Landing, commissioning of the complex commenced in June and has continued. Through the next 6 weeks, we will be fully testing and starting up the front-end amine plant, and we expect to have the necessary electric power to also fully load the facility. Taken together, we expect to ramp to full commercial in-service by late September.

In speaking with our producer customers in New Mexico, we continue to build conviction on just how highly economic the rock formation is in Northern Eddy and Lea Counties. However, much of the associated gas carries substantially higher CO2 and H2S content.

To support further development of the resource play, we have filed a permit for an acid gas injection well at Kings Landing to sequester the growing levels of CO2 and H2S. Lead times for specialty equipment and materials can be upwards of a year, so our team has been prudent in identifying these items to jump start this process.

We expect to receive approval to proceed by year-end. Upon in-service of the AGI well at Kings Landing, Kinetik's total acid gas or TAG capacity is expected to more than triple and further position us to be a best-in-class gas gatherer, treater and processor with a differentiated service offering in Northern Eddy and Lea Counties. We look forward to sharing more as we progress this opportunity.

To support the conversion of Delaware North to a primarily sour gas system, ECCC pipeline is a critical component to move sweet-rich gas from New Mexico to Texas and free up additional processing capacity in New Mexico.

Construction has started, and we expect in service in the first half of 2026. The proposed scope includes restarting our Sierra Grande processing facility and adding boost compression there. We have the ability to increase ECCC's throughput capacity to approximately 300 million cubic feet per day for sweet gas, with system looping in Texas.

Looking ahead, the investments we have made and continue to make across our system provide a multiyear earnings tailwind through the end of this decade. First, Kings Landing is our beachhead position in the Northern Delaware. Our conviction continues to grow regarding expanding our footprint and volumes around this complex.

Our commercial team has been very active advancing some really exciting opportunities. And with much of the pre-FID work for a processing expansion at Kings Landing behind us and permitting for acid gas injection in progress, commercialization of an expansion and sour gas conversion remains on track.

Our low and high-pressure build-out in Eddy County continues to perform better than expected with well results exceeding expectations. Customers and other active producers continue to add inventory in the area, increasing the project earnings potential and duration.

Acquired earlier this year, the Barilla Draw gas and crude gathering systems are performing well and are expected to contribute to earnings growth throughout the decade. Additionally, well connects in Lea County in the second half of this year will contribute additional volume increases.

So based on the current estimates and with continued commercial success, we expect that additional processing capacity besides Kings Landing 2 is likely to be needed inside the next 18 months as our Delaware South processing capacity is fully utilized with ECCC pipeline.

We also remain focused on optimizing our cost structure. In the past few years, we have experienced and managed meaningful cost inflation, especially with electricity and leased compression. And while we think the worst of it is behind us, it underpins our conviction to pursue the behind-the-meter power generation opportunity in Reeves County and the owned compression solution over the next several years. Both projects would compete for capital and provide long-term structural solutions to offset these inflationary pressures.

So before I turn the call over to Trevor to discuss second quarter results, I want to reiterate the opportunity set in front of us today. Our organic and inorganic growth pursuits over the past 1.5 years have positioned the company for accelerating growth as we head into 2026.

We continue to expect fourth quarter 2025 annualized adjusted EBITDA of approximately $1.2 billion, which represents 24% growth year-over-year. And this is just the beginning of a very bright multiyear earnings growth and free cash flow generation outlook that presents a compelling investment opportunity for existing and future shareholders.

So with that, I'll now turn the call over to Trevor.

Thanks, Jamie. In the second quarter, we reported adjusted EBITDA of $243 million. We generated distributable cash flow of $153 million and free cash flow was $8 million.

Looking at our segment results, our Midstream Logistics segment generated an adjusted EBITDA of $151 million in the quarter, up 3% year-over-year on increased processed gas volumes from our Northern Delaware assets. This year-over-year increase was mostly offset by lower commodity pricing and higher OpEx, both of which I will cover in more detail shortly.

Shifting to our Pipeline Transportation segment. We generated adjusted EBITDA of $97 million, up 3% year-over-year, which benefited from an increased ownership in EPIC and modest outperformance at PHP. The year-over-year increase was partially offset by no contributions from Gulf Coast Express following the sale of that stake in the second quarter of 2024.

Total capital expenditures for the quarter were $126 million. With the updated in-service timing for Kings Landing and the other impacts I just mentioned, we are revising our 2025 adjusted EBITDA guidance range to $1.03 billion to $1.09 billion.

Now I will walk through each of the impacts in more detail and the implications to guidance. First, we revised our full year processed gas volume growth assumption from 20% in February to mid-teens to reflect the shift in timing of the Kings Landing start-up and modest delays in producer development activity.

For the remainder of the year, we expect a meaningful ramp in processed gas volumes driven by the full commercial in-service of Kings Landing in late September and step-up in contributions from the Barilla Draw, Carlsbad and Lea County volumes by year-end. We anticipate exiting 2025 with processed gas volumes at approximately 2 billion cubic feet per day.

Second, we have seen significant commodity price volatility since setting our initial guidance in February, creating a headwind in the second quarter and a change in our assumptions on market forward pricing.

On a weighted average basis, our revised guidance assumes a 10% decline in commodity prices versus our original guidance in February. Marking to market realized pricing and forward pricing, we estimate this decline to represent an approximately $20 million impact versus our original adjusted EBITDA guidance.

At current commodity prices, approximately 35% of our direct exposure is tied to the price of WTI, 20% to the price of natural gas, 25% to the price of LPGs and the remaining 20% to basis and commodity price spreads. We have significant hedges in place for the remainder of 2025 and a robust hedging program for 2026 and 2027.

Moving on, operating costs continue to persist in the Permian. We have seen substantial cost inflation across lease compression and electricity, 2 of our largest operating expense line items. Year-over-year unit cost per Mcf increased by approximately $0.10 in the quarter.

With the commissioning and the start-up of Kings Landing, unit cost per Mcf are expected to modestly step down as volumes come online. On a full year basis, we anticipate unit cost to be up approximately $0.06 year-over-year in 2025. While much of this increase was expected and included in our original guidance, we have experienced higher-than-budgeted operating costs as well as the need to retain lease compression units for new areas of development that we originally planned to release.

Taken together, these impacts led us to revise 2025 adjusted EBITDA guidance approximately 5% lower to $1.06 billion at the midpoint. Importantly, as Jamie discussed earlier, we continue to expect a meaningful acceleration in adjusted EBITDA growth through the remainder of the year and to reach annualized adjusted EBITDA of approximately $1.2 billion in the fourth quarter.

Turning to capital guidance. We are tightening our range to be within $460 million to $530 million, given our heightened visibility at this point in the year. We anticipate CapEx to be concentrated in the third quarter with the timing of Kings Landing completion and construction of ECCC pipeline. That said, we now expect nearly 60% of 2025 capital to be spent in the second half and nearly 45% in the third quarter alone.

Before I open up the line for Q&A, I will touch briefly on our finance-related objectives. At the end of May, we completed a total refinancing of our bank debt, extending maturities on the Term Loan A and revolving credit facility.

Our leverage ratio per our credit agreement stands at 3.6x at the end of the second quarter. We also repurchased $173 million of Kinetik Class A common stock since May, representing nearly 2.5% of our outstanding shares at an average share price of approximately $43.

Our share repurchase program reflects our commitment to delivering value to shareholders, and I'm enthusiastic about utilizing it in light of the disconnect we see between the market price and intrinsic value of Kinetik stock.

Our finance-related objectives provide the framework to maximize shareholder value via our multiyear earnings growth and strong balance sheet, bolstered by strategic and accretive investment opportunities, annual dividend increases and opportunistic share repurchases. I am excited with the progress that we have made in the quarter and look forward to delivering even more value to shareholders in 2025 and beyond.

And with that, we can open up the line for Q&A.

[Operator Instructions] Our first question comes from Jeremy Tonet from JPMorgan.

Just wanted to start off, if we could here. If we look at the exit rate for 2025 for 4Q there, just wondering if you could walk through the building blocks that get you there and the confidence level of exiting the year in that $1.2 billion run rate.

Sure. And look, a very valid and very good question. Look, the -- when you break down $1.2 billion, think about it as $300 million for the quarter. So we had $243 million for the second quarter. And as Trevor went through, we have already endured a lot of the operating cost impacts as it relates to high electricity pricing, higher compression leasing. So really, the building blocks from here to get from a $243 million. You're going to have a little bit of APA non-curtailment and maybe in the fourth quarter. That's what you should anticipate.

Obviously, we had it in the second quarter, as everyone knows. I think the biggest one is going to be KL and Durango, obviously. And then you're going to have some incremental volumes. We've had some volume shift from third quarter turn in line to fourth quarter, which has, I think, tempered a little bit of the overall growth rate on the volumetric side. So, our exit rate remains pretty strong. However, because it's now in the fourth quarter and not the third quarter, you don't get that flow-through as far as duration of that volume for this calendar year.

So, I think that are the 4 buckets. Everything else sort of stands pretty much as it is. And I think our degree of confidence Look, Kings Landing, I think we have really taken a measured approach as it relates to making sure that the plant is running and that we have got the plumbing. It's as much about the plumbing and separating out the sour gas from the sweet gas, which to this point, had all just been going, whether it's to Dagger Draw or to Miyajima. And now we have to separate, free up space on the sour gas side, which is the Miyajima and Dagger Draw facilities.

And for the less sour gas send it to Kings Landing, even though we have front-end amine, we still don't have an AGI. So, we can't handle really, really sour gas at that facility. So we have been very methodical. I would say it's probably taken us longer. We were probably a little overoptimistic on how quickly we could get it done as far as the replumbing of the gas. But I think our confidence level now, Jeremy, is really high. It's really high.

We know where the gas is. We've spent so much time. So maybe it's a little frustrating to get out of the blocks a little slower than many of us would have liked, including ourselves. But I think the follow-through and as we hit our stride, as we come out through the back end of this year, I think we will be the better for it.

Got it. Just wanted to pivot to buybacks, a good amount in the second quarter. Is this a rate that we can expect to continue here? Just wondering if you could provide more color on what that cadence could look like?

I think it's a function of -- and Trevor can jump into this. It's really a function of where our stock price is. We see the stock in the low 40s as being incredibly compelling. And so, he is driven with more of a lead foot this past quarter, starting obviously in May. And I think, look, we will take cues from the market. We understand, we look at our capital allocation framework. We work out and we see where fundamental value is and where we really like the stock. And so, we will basically be attuned to how that -- to what we see on the screen.

Our next question comes from Spiro Dounis from Citi.

I want to start with NGL re-contracting, if we could. I think it's more of a 2026 tailwind, but curious if some of the NGL pipeline operators are eager to negotiate early and make sure some of those volumes stay on the system. In other words, could we see that recontracting tailwind maybe coming earlier than expected?

Spiro, look, it's a really good question. Obviously, we all know that I think Enterprise said that they expect by here to start up in the fourth quarter. So that occurs. And obviously, between Enterprise, Targa and Transfer, obviously, ONEOK and DCP as well as MPLX now. We have a much bigger grouping of NGL integrated players than probably ever before.

And with, I would say, tempered enthusiasm and expectation on growth in the basin. With a lot of capacity to fill, we continue to see some pretty interesting overall indications and rates coming from different NGL service providers. You're right, in our context, we have 2 contracts that roll off next year. One is already -- you've got Targa steps into the shoes on one of them and the other is basically free to decide.

And then in '27, we'll start off with Kings Landing once we reach the 2-year in-service mark. And then we follow from there. We've got literally almost serial expirations going on through almost the end of the decade and other contractual adjustments. So, I really do think we're going to be able to capitalize on it. We've always said that. and we'll sort of see where that takes us. But I think it's a good time to be on our side where you've got product. And there's a lot of capacity in the marketplace and obviously, a lot of people eager to fill that capacity.

Got it. That's helpful, Jamie. Second question, switching gears to Kings Landing 2, and I apologize if I missed it in some of the prepared remarks, but can you describe maybe what inning you're in there as you think about progressing towards FID and how we should think about some of the gating items? And sort of in that context, I think you talked about 18 months is when you need it. Any sense on whether or not you could use offloads to sort of bridge that and push that CapEx out a little further?

So I think we're sort of mixing a little bit of metaphors. On the 18 months that was mentioned, it was actually in relation to processing capacity in Texas over and above what we have and over and above anything we decide to do on Kings Landing 2.

On Kings Landing 2, the core building blocks of that particular project, one is clearly commercial. The other 2 is, one, acid gas injection because it does need to be a sour plant. And that is a longer lead time item as it relates to both permitting as well as sourcing equipment. The other, obviously, is electricity, which is quite -- which can be a challenge, and it seems almost more of a challenge than in New Mexico than it does in Texas.

And so, when you ask us about what inning we're in, Look, I would say if you're thinking that the inning concludes with an FID announcement, right, the gain -- if that's the end of the ninth inning. I would say we are midway into our overall work stream as far as we've already filed permit application for the acid gas injection. We're well advanced on the electricity. The commercial guys have been working this for a long time.

We've got some pretty big customers sitting behind the Durango system that I think with the advent of Kings Landing 1, and seeing for their own eyes that, that capacity is there, will give them the conviction, which thus far, they've sort of been hesitant about to actually go spend money on the drill bit and accelerate a development program. So, we have got everything moving together on various work streams, and I think it will all come together, our hope and expectation, certainly within the next -- I would -- certainly before year-end.

And Spiro, this is Kris. I wanted to jump in quickly on the comment on offloads. We're always going to look at optimizing our portfolio with capital and offloads. And that's why ECCC is so important. It allows us to get south where we have a number of more economic offload options. So, we'll continue to look at all those as options to optimize the portfolio.

[Operator Instructions] Our next question comes from Michael Blum from Wells Fargo.

I wanted to start with a macro question on the fundamentals. So, I guess we're seeing some Permian midstream players maintain guidance and tell us that basically producer activity is unchanged. And then we have others that are tweaking guidance lower like yourself and pointing to a weaker fundamental macro. So, I just want to get your take on what's going on from a macro perspective and then, of course, what's going on in your neck of the wood specifically?

Sure. Michael, I think we're seeing a few things. Obviously, as a Permian pure play, I think there's nowhere for us to literally run and hide, right? We don't have any other basins. So, we can't mask any declines in the Permian against increases in the Haynesville or other basins that may be more gas focused.

What we're seeing is, let's -- I mean, we can knock down our big customers. PR, EOG, Katera, I mean, we can pretty much go through them all since we have almost 90 customers. But PR hasn't changed rig cadence. In fact, their overall performance on their wells has exceeded their own type curves and expectations. So, they may move a well pad from the third quarter or the fourth quarter to the following quarter or the beginning of 2026. That doesn't change their guidance. It doesn't change their fundamental view of the quality of the rock. If anything, what it does is show you that actually it's even better than they anticipated. But they're not -- much like I think all of us right now, they look at their own probably stock price and say, look, should I keep capital in my pocket because I can save some dollars and I'm still going to hit my guide on overall BOEs.

So, I do think in Texas, we have always maintained the Texas position is more today. We see some spots of activity. Barilla Draw is one area. But the Barilla Draw activity, honestly, Michael, Trevor and I would tell you, offsets some of the legacy Centennial activity that we saw the year before from Permian Resources.

So, we do see some give and take. Texas remains, I think, more of a -- it's not the prime and the sort of ultra Tier 1 acreage that we still see New Mexico. I think New Mexico holds for various reasons, a lot more attraction and appeal from just a -- maybe it's a cost standpoint, maybe it's an administration standpoint that they think now is the time, basically get in while they're going is good.

And Texas, you can pivot back to. You can always pivot back to Texas because it's very dynamic. It almost can be that -- it can very much be that production that just comes on very quickly. So, I wouldn't read too much into it that we're seeing a huge slowdown as it relates to the overall level of activity. I think what we are seeing is we've seen some shift in timing, but it's timing. We are seeing quality of results and quality of -- from a type curve standpoint at or above our expectations.

We said to you that Carlsbad, which is another PR position, has been exceptional. Barilla Draw has been very solid. So, we're really excited by what we have. And I think our viewpoint is, look, we will catch up and we'll end up with some tailwinds in the face of what has been thus far, certainly for this year, more headwinds on whether it's commodity pricing or whether it's in the context of just OpEx costs. Trevor, I don't know if you've got anything you'd add to that?

Yes. The one thing that I'd add, thanks for the question, Michael, is from where we sit from the beginning of the year, prior to the $10, $15 sell-off in WTI is we're not seeing much of a change to the second half of 2026. What I would say is that, Jamie had mentioned there's been some shifting of timing and some pads, both north and south. A lot of them what we're finding is actually not necessarily for noneconomic reasons in terms of the primary driver, sure, WTI goes into it. But what we're actually seeing is that what we need to do as a company is to get in front of our customers with infrastructure to facilitate the upcoming development plans that we're seeing up in Delaware North. And that's why getting ECCC completed is critical, as Kris had mentioned earlier, we pointed to a potential expansion of that pipeline, FIDing sometime in 2026. We've talked about Kings Landing 2. And really, I'd say that's what we're extremely focused on in terms of getting that across the finish line with an FID because there is no real change to, I'd say, as we think about a broader portfolio of Delaware North plus Delaware South, what we're really seeing from where we were at the beginning of the year. If anything, we've actually seen a bit of an acceleration in certain areas that's offsetting some of the, I'd say, timing shifts or delays that we're seeing elsewhere.

Okay. Got it. That's a very helpful perspective. I appreciate it. The other question I wanted to ask -- in the prepared remarks, if I heard it correctly and understood it correctly, it seems like you're seeing the gas is actually getting even, I guess, more sour, for lack of a better word, than even what you were anticipating.

So just trying to understand, is that a potential upside case for you guys, whether that means you can either raise -- I don't know if that means you can increase the treating fee or just you're going to see higher volumes on those fee -- the existing fee. But I just want to just understand if there's anything there on the upside case.

So Michael, you're right. It is even more sour. I think the first and the second Bone in particular, are very sour. And therefore, the only way to actually manage that gas is with acid gas injection. So, by the addition of acid gas injection at Kings Landing, we will, I think, triple the size of our tag capacity, treated acid gas, and we will be amongst the biggest in New Mexico in the context of tag capacity. It will allow us, depending upon -- from a tiering standpoint, it will allow us to obviously get an economically attractive return, but we are putting significant incremental investment and capital into infrastructure to allow us to be able to treat that gas and process that gas. So, I think you will see, yes, it is more sour. Yes, you will have there's probably more upside in the context of rates and fees depending upon just how sour.

Our next question comes from Brandon Bingham from Scotiabank.

I wanted to go back to the building conviction in Northern New Mexico that you guys have discussed. And just if you could provide any incremental detail around some of the commercial momentum or just anything you're seeing up there that's really helping you build that conviction in the area and how that might kind of translate into any potential KL2 FID timing?

Yes, sure. Brandon, it's Jamie. And I'll let Kris and Trevor jump in. Look, we have a number of customers up there, as you know, that we inherited with Durango, the larger ones of which are Spur and Newborn, they are both very eager to put incremental capital to work on the drill bit and need, as Trevor pointed out, infrastructure. Kings Landing 1 is you just knock it down and just move on through. They need -- they want us to do the AGI because they very much see the most -- some of the most attractive rock being that, as I mentioned, as I just referred to Michael Blum's question, First Bone, Second Bone, really sour gas. but it's really attractive, and they really want to get after it.

So right now, I feel like we are sprinting to keep up with our customers and their desires. We can't -- I think Kris Kindrick would tell us, we probably can't sprint fast enough to make these guys thrilled and happy yet because they want to spend the dollars tomorrow. And unfortunately, it takes us longer than tomorrow to actually have the infrastructure up and online.

Yes, Brandon, this is Kris, kind of echoing on what Jamie said, there's a lot of activity in front of us, probably more so than we've seen in the last 2 years. And Jamie hit on New Mexico. But even in Texas, we're seeing opportunities. And now with ECCC online next year. We look at this as one combined system where we're introducing volumes across the system. So, it's a huge growth opportunity across the majors, the independents, the private producers.

2026 is going to be an exciting year and not just for new packages of gas, but there's some big developments on our existing acreage in '26 that we'll need to accommodate. So, it's an exciting time, and the team is doing a good job tackling these commercial prospects.

Okay. Great. And then maybe I wanted to kind of touch on Epic a little bit. If there's any updates there, maybe around timing of distributions or just how you're thinking about it in general as one of your partners in it has discussed that it's comfortably up for sale if they need to or it's something that they're willing to sell. So just kind of any updates on Epic and anything you can share there?

Sure. So as far as on the distributions, I believe the first distribution is going to partners this month. So, I believe that, that's been authorized and approved, which is great. And the business is actually performing very, very well.

As far as the designs of the various partners and certainly one of -- probably the largest customer in that pipeline and what they may want to do. Look, I think from our vantage point, it's like any asset. It has an intrinsic and extrinsic value to us as a company. if, in fact, the value proposition of somebody else is at or above that value expectation from our end, then I think we would be remiss in not capitalizing on it, right?

We're looking to create value for our stakeholders. So, if someone shows up with the right number, then I think we're not so wedded emotionally or otherwise to this asset to say that, oh, it's a must-have. It's a non-operated stake. So, it's not as core as other elements certainly of our business. Trevor, do you have anything to add to that?

Nothing to add to that. I think you hit it.

[Operator Instructions] Our next question comes from Theresa Chen from Barclays.

On the topic of TAG capacity and the TAG market in general, with one of your midstream competitors announcing entry into sour gas treating recently via an acquisition in what seems like a similar area of service as your footprint. How do you think about competition within this space evolving over time?

Theresa, it's Jamie. Thanks for the question. Look, it's a good question. Obviously, MPLX buying Northland. Yes, obviously is -- brings them now into the equation. Thus far, it has been more of the domain with enterprise buying Pinion, ourselves and obviously, Targa with Red Hills, right? So as part of the Lucid complex.

So look, there's certainly more than enough volume and development for many, many players. And I think it's not a case of where -- if anything, we're going to see sour gas on the CO2 H2S side, I think, continue to dramatically increase. versus dramatically decrease. And therefore, the overall size of the market is getting bigger. And therefore, I think there's room for everybody. It still takes a long time to get into this business.

Obviously, I think that was, if I'm not mistaken, was one of the major principles for the enterprise acquisition of Pinion, which was when they looked at it, they said it was going to take them 3 years otherwise. And from our vantage point, we said this all along. We said we like to see where the puck is going, and we could see that sour gas was obviously really going to be on the front end.

And so, the acquisition of Durango gave us that entry point, and we've obviously looked to capitalize on it. So, I think there's plenty of room for everybody. Do I expect it to continue to increase? Look, I think others will start to see for those that have the existing infrastructure and are able to capitalize on it, it will be a very attractive business. And for others, they may look for entry points.

Understood. And within your own organization, given the commodity price volatility and the impact that it's had year-to-date, how has your hedging strategy evolved, if at all? How do you view the impact of either absolute prices or spreads as we go through the next few months of 2025 and into 2026? And would you expect the net impact to be maybe more muted next year versus this year? How should we think about this?

Yes. Thank you for the question, Theresa. What I would say is that the year-over-year impact from '24 to '25 on pricing is approximately $20 million. So, when we entered the year, we thought it was going to be flat on a year-over-year basis. And as we have disclosed relative to our original guidance, it's about a $20 million headwind. What I would say is that, I'd say, we're more active and we're reaching further out relative to, I'd say, historical norms to try to, I'd say, levelize these year-over-year impacts on margins on the commodity side. So, as we look forward into 2026, I would expect it to be relatively flat in terms of an impact on a year-over-year basis.

Our next question comes from Keith Stanley from Wolfe Research.

Wondering if you could give any early thoughts on where you see CapEx kind of evolving over the next couple of years. There's a lot of growth you're talking about with KL2, maybe another plant in Texas, AGI capacity, power plant. Just how do you see CapEx kind of evolving next year and into 2027?

Brilliant question, Keith. It is the topic that I think that Trevor and I spend the most amount of time just thinking about, because there's a realization -- and there's a reality to us and the size of our company that we can't do everything we want, right? We've said this on more than one occasion. We're a company that wish we were a $5 billion EBITDA company and not just over $1 billion EBITDA company.

So, I think we are recognizing and really trying to rationalize where do we need to spend capital, what's that timing of capital. To us, what are the core elements? I think if you ask us, I think Trevor would and I would tell you that, obviously, you get some really good bang for your buck on expansion of ECCC, you can do that pretty cost effectively.

Kings Landing is pretty -- Kings Landing 2 is very important, particularly if you're doing it in conjunction with the acid gas injection. And that is higher-margin gas. And then you've got to think about, okay, well, what are you going to do in Texas? Are you going to have offloads for some time? It's sort of a conversation we have with the commercial team. Do we think about bridging that then and sort of managing our overall capital bucket.

But I think, Trevor, we've said what consistently, 25%, 30% of EBITDA in the context of around 30% of EBITDA in the context of our overall capital allocation for reinvestment -- I mean, realizing that it's not perfect with the percentage, but just to give a sense.

Yes, that's right. And a little bit more elevated in years in which we're building plants. But what I would say is, as Jamie pointed out in the beginning, in terms of just our financial profile, with the opportunity set that we have being top to bottom east to west in the Delaware Basin is we've got a lot of opportunities that we look at, and it allows us to be a little bit more patient and diligent in picking the right lanes for us to allocate capital towards.

Our next question comes from Jackie Koletas from Goldman Sachs.

Just a little bit on that point on capital allocation. With higher operating cost inflation, how are you thinking about the cost reduction plan effort, the compression deployment and behind-the-meter power and the timing of potentially implementing those projects, especially balancing out potential spending on those growth opportunities that you mentioned?

So Jackie, I think we look at it as follows. As it relates to compression, compression, you can leg in. You can do a little bit. It's more about you're going to put an order in today, and it might be 50, 60 weeks from now before you're going to see those compression units arrive. So, it's more timing. If you need something just in time, meaning inside 6 months because you get -- you're about to do a low-pressure connection, then unless you have some existing compression that you're able to go and move, you're really in the domain of having to go and undertake a lease for some term with one of the compression service providers.

I think what Matt Wall, Trevor and I have decided and what we have already started to do is we put down some deposits for incremental compression that's going to come to us over '26 into '27. And that will continue. We think it's very cost effective, highly cost effective versus other options. We get better run times or better uptimes with it. I think we've just seen improved reliability, and we've now got to a size as far as our compression skill within the company that, look, we can keep these units up. And I think we've got the mechanics, capability, spares that literally means we can do this.

So compression is a little different. It's different than a power plant because power plant, you can't really leg into it. You just got to decide what's the size of the power plant you're going to go do. And I think what we're doing is we're also -- one of the things that certainly has come out of our keen interest to try to, I would say, minimize and just control our overall power cost is we have been approached by external parties. Some of -- obviously, there's a large amount of generation that's to be built in Texas.

So, we're going to look at various options. For now, we have a fixed price fixed block. We went and source that out of a retail electric provider. So, we've bought ourselves enough time to be able to manage and make sure that further cost inflation doesn't erode our bottom line. So, I think what we're trying to do is just manage it. right? Management as best we can, much like we have historically. I think the first -- you'll start to see some benefits, but not until probably, I think, '27 on the compression side. But again, it's going to be small steps.

Got it. I appreciate the color there. And then just as a follow-up, wondering if you could provide us an update just on your appetite for bolt-on M&A, how you're seeing valuations trending today? And if there are any other opportunities similar to Barilla Draw.

We will look at everything. I think our viewpoint is that overall multiples have gone up. I think recent deals prove that. I think we look at that in conjunction with where our stock price is, and we say, well, it's not really the right time to think about doing something aggressive on the M&A standpoint.

And if we've got capital to deploy, we'd much prefer to go deploy it in building a new Kings Landing 2 plant or an acid gas injection well that would be a low single-digit multiple. And we've got literally all the conviction to go and get it to basically get it commercialized and done. So, I would say we are more focused on organic at this point. That is, of course, not to say that we will exclude looking at inorganic, but it would have to be incredibly compelling.

Our next question comes from Saumya Jain from UBS.

So, you've had a greater CapEx allocated towards Delaware North, especially Kings Landing versus Delaware South. But now with Birla draw contributions and ECCC pipeline under construction, do you see potential in further rolling out Delaware South more? I guess, could you expand on the different opportunities you're seeing in the North versus South longer term and how you're considering the CapEx split in the future?

Look, I think it's a very good question. I think the fact that we have investing and invested thus far more in Delaware North is, I think, just a reflection of how much activity is up there and the fact that it is so underpenetrated from an infrastructure standpoint versus other areas.

ECCC really does unlock. It's a really new dimension to a business because now you can move sweet, rich gas from New Mexico down into Texas. So, as we -- as you all probably will remember and know, we have more of a sweet system. Yes, we have front-end amine treating, but our overall ability to handle really, really sour gas is more limited in South Texas.

I think as we continue to see New Mexico be the hive of activity for our producer customers, that's where you'll see the preponderance of our overall capital deployment. When at some point, that will pivot and it will come back, ECCC is an example where we're actually capitalizing on New Mexico, but it's going into Texas, and we may need another processing facility getting built. So that would obviously create incremental capital spend in Texas. So I really do think we're just going to balance it based on what we see and what occurs as it relates to our producers and where that opportunity set presents itself.

Got it. And then you noted how producer development plans were delayed into 2026. I guess, could you provide more color on how we should expect to see producer activity in the back half of the year and the key drivers there? And what -- and I guess, help us understand some of the sensitivity within your growth outlook to basin level growth specifically.

Trevor, do you want to jump in on that?

Yes. I'll point back to some comments that Jamie made at the beginning of the year as we think about from where we are in the second quarter to the exit rate of $1.2 billion. Obviously, with Kings Landing coming online, that's a significant contributor of both volume and earnings growth.

And then we're seeing, I'd say, part of the shift that we have seen is really just as producers looked at their TIL schedules and with some uncertainty in the timing of Kings Landing, that really had shifted things a quarter or 2. And so we start to see significant, I'd say, well developments up in our Delaware North area, both in Carlsbad and then up in -- where the Kings Landing area is and up on the shelf. And then Jamie pointed to at the beginning of the call, we start to see some real nice big packages of development in Delaware South and specifically in the Barilla Draw area as we exit '25 and into 2026.

With respect to basin level growth, we've been -- we have a page in our monthly investor presentation where we index it back to 2021, and we've consistently outperformed broader basin level growth, and we continue to see that to -- or excuse me, we expect to see that continue, especially as Kings Landing comes online. That's a bit, I'd say, unique relative to Kinetik, and it's almost 10% of total processing capacity growth for us in a single quarter. And so, I'd say that, while it has been a little bit flatter relative to overall basin growth, still, I'd say, either in line or modest outperformance, we expect that outperformance that we have seen in '21 through '24 to really pick back up again.

And Saumya, this is Kris. Just hitting back on something Trevor hit on. Each customer is different on why they're delaying. Some of them are optimizing rig schedules. Some are testing reservoir properties. But the rock is still great rock, and we're excited about what's on the table in 2026. There's some large packages, and there's going to be some good development there. So again, each customer is different, and there's different reasons for the delays.

We currently have no further questions. So, I'd like to hand back to Jamie Welch for any further remarks.

Thank you, everyone, for your time this morning. We know it's a very busy time in the quarter, and we look forward to catching up with you soon. Thanks very much.

As we conclude today's call, we'd like to thank everyone for joining. You may now disconnect your lines.