ewsba.se
Chief Executive Officer — Jamie W. Welch
Senior Vice President, Commercial — Kris Kindrick
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Jamie W. Welch: Thank you, Alex. Good morning, everyone. Kinetik Holdings Inc. 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 Holdings Inc. is incredibly well positioned as these dynamics continue to play out. Commercially, our team has been highly productive. We have seen strong conversion of opportunities into new and amended agreements across both Texas and New Mexico.
Over the past few months, we have 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 have 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 King’s 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 the King’s 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, with in-service later this quarter.
At King’s 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 Acid 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 one of the sour conversion to King’s 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 Cryer. Turbine equipment has started to arrive on site, and engineering, procurement, and permitting work is well underway. 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.
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 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 Holdings Inc. 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. 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 Holdings Inc.’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 multi-year plan has only increased over the passage of the last 90 days. And with that, I will turn it over to Trevor.
Trevor Howard: 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 the 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 Chinook. 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 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 six 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. 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. 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 Bcf per day of new capacity is expected to be in service by early 2027, with an additional 6 Bcf per day anticipated across 2028 and 2029. This structural shift has reinforced the 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. We will now open the call for questions.
Operator: We will now begin the question and answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A list. Your first question comes from Michael Blum with Wells Fargo. Please go ahead.
Michael Blum: Thanks. Good morning, everyone. I wanted to ask about the Durango agreements that you amended and extended here. How do we think about the incremental EBITDA contribution for 2026 and beyond? And with these new agreements, does this change at all the mix of your contract portfolio between fee versus POP and keep-whole, or just your overall commodity exposure?
Trevor Howard: Michael, thanks for the question. In terms of 2026, I would call it, as we have characterized in the past, a modest uplift—so 1% to 2% of the overall base business. It is a nice uplift, but it really sets the stage for reinvesting in the field and also investing in King’s Landing further with the sour conversion and then the potential processing expansion, by pushing out the duration and term of those agreements. It also has removed a portion of commodity within the business. When we acquired Durango, the system was about 60% fee and 40% commodity. Through these restructurings and amended and restated agreements, we have taken that fee-based percentage up.
Not quite like our business down south, where that is an 85% to 90% fee margin business, but we are closing the gap there.
Michael Blum: Got it. Thanks for that. And then I wanted to ask on this Pecos Power deal. How do we think about returns for a project like this? And do you see other opportunities in the basin to replicate this? Because that is another way to deal with Waha—finding more in-basin demand for gas.
Jamie W. Welch: Thanks, Michael. As far as the returns, there is no capital, so it is infinite in that context. We are 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 have a very active dialogue with a number of them. You are correct. We look at it much the same way you pointed out, which is a little bit of self-help for Waha on the basis of creating incremental demand.
We will continue to capitalize on it and, from our vantage point, it is a nice incremental base of fee revenue.
Kris Kindrick: Hey, Michael. As Jamie alluded to, it is an earnings opportunity not only to sell residue gas transportation, but a lot of these power companies want hourly services too. To the extent we can provide that flexibility, that is additional margin. We are in conversations with these parties right now, and it is future upside that we are working on.
Operator: Thank you. Your next question comes from Spiro Michael Dounis with Citi. Please go ahead.
Spiro Michael Dounis: Thank you, operator. Good morning, team. I want to start with King’s Landing 2. You announced these new dedications. You talked about growth accelerating into early 2027. Trevor, you just mentioned a lot of this sets the stage for an expansion. How close are you? I think, originally, the potential FID was a 2026 line item. Where does that stand? Is there maybe even a capital-light option you could pursue first?
Jamie W. Welch: Spiro, good morning. As far as King’s Landing 2 is concerned, we have been actively engaged in commercializing that project opportunity for some time. We have knocked down incremental steps along the way which bring us closer and closer to the endpoint of finally being able to FID that particular plant. I think we are getting close, and the overall level of activity we continue to see reinforces our belief in the prospects and opportunity that we find in New Mexico. In the interim, as you know, ECCC will come into service in a month from now. We will be able to start taking incremental, what we would say, sweet New Mexico volumes down south for processing capacity.
We will continue to look at the level of activity more broadly in New Mexico, which remains very robust.
Trevor Howard: And on your last comment about the capital-light option, really, ECCC was that option. Because Delaware North was on an island and not connected to our Delaware South system, King’s Landing 1 is going to get filled this year, and we would have needed King’s Landing 2 in service by the end of this year to take incremental gas. We took that measure with ECCC, allowing us to utilize processing capacity in other parts of our system. There are also more markets and more optionality down in Texas.
Spiro Michael Dounis: Got it. Understood. Going back to the 2026 EBITDA cadence, could you give a bit more detail on the drivers for the back-half ramp? Waha likely is not improving until maybe mid-summer. There are indications Hugh Brinson could come online by that time frame and help provide some relief. How are you thinking about when the marketing gains flip to curtailments coming back online and volumes being the bigger driver? It sounds like that is what you are counting on for the back half of the year.
Jamie W. Welch: I think Trevor will answer this, but what we announced with the incremental expectation for curtailment is that we foresee a continuing period of challenge for Waha. For the sake of being conservative, we wanted to communicate that the overall level of curtailments was higher than we anticipated in our original guidance. More importantly, it is deferred revenue. That volume will show up, and in the meantime, we have found a bunch of value in the form of these marketing revenues that have ensured we met our financial guidance and created a net windfall for our stakeholders—because you have money from marketing, and you are going to have deferred revenue coming from the return of production.
Trevor Howard: Also, piggybacking off Jamie’s comments, it makes it easier to grow in 2027 because the PDP base starting off in January 2027 will be higher. Again, Jamie’s comments are right: it is deferred revenue. PDP will be higher entering 2027, so it really sets up 2027 well. We have talked at length about the strategy we have employed with the Gulf Coast marketing hedge as an offset to curtailments. It has been effective.
With respect to the ramp in the back half of the year, I would reiterate my prepared remarks: no changes to our second-through-fourth-quarter earnings cadence—$230 million to $240 million in the second quarter and $260 million to $270 million each quarter in the second half of this year. What is driving that is not a return of shut-in volume. We are expecting shut-ins to persist through the balance of the year and really resume in December. When you look at the forward spreads, Waha is negative up until October. We have taken a little bit of conservatism, given that is a maintenance period, and we wanted to ensure we are out of the maintenance season before expecting volumes to return.
The drivers: we have a very summer-heavy development program and a handful of big packages of gas coming online across the system, particularly in New Mexico in the third quarter. In the fourth quarter, we have some Texas packages that are real needle movers for gas volume growth. Then come December, that is when you have the resumption of curtailed volumes and then Gulf Coast marketing margins declining.
Jamie W. Welch: Spiro, it is interesting that we sit here in May and we have only had Waha being in positive territory—greater than zero—for 13 days; six days were attributed to Winter Storm Fern. Excluding Winter Storm Fern, seven days, and we are now in the fifth month of the year. We are dealing with unprecedented volatility. Even at the beginning of this year, we thought 2026 would be the tale of two halves, but seeing negative pricing for Waha going into October is truly hard to fathom.
Trevor Howard: One more comment on the volume revision lower in our year-over-year volume guidance. As you saw, we increased our curtailments by 120 million cubic feet per day on average for the full year. That is about six percentage points to our overall gas processed volumes. We went from high single-digits year-over-year to low- to mid-single-digits year-over-year, solely attributable to the increasing curtailments.
Spiro Michael Dounis: Understood. Helpful color as always. Thank you, gentlemen.
Operator: Your next question comes from Brandon B. Bingham from Scotiabank. Please go ahead.
Brandon B. Bingham: Good morning. Thanks for taking the questions. I wanted to go back to the setup into next year. With 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 pent-up supply beyond the expected curtailments as prices normalize?
Jamie W. Welch: Brandon, as prices normalize, do you mean gas prices or normalized in the context of Waha pricing?
Trevor Howard: Okay. It is interesting because what we have tried to communicate in both the press release and the prepared remarks is that we have this push-pull impact right now for 2026 in activity. We are seeing some of the smaller independents pull forward packages in a matter of weeks or months, but we are seeing a building momentum in 2027. We had estimated second half of the year or middle of the year, and people are pulling forward packages into the very beginning of the year.
The longer we have this elevated commodity price environment, the more we are going to see, particularly from our larger public customers, a lot more activity in the beginning of 2027 that capitalizes on that continued tailwind. That sets you up for an even better 2027. Not only will we have the return and a higher PDP base because of the shut-ins effect, but we also have a real pull-forward of a lot of activity.
Brandon B. Bingham: Great. Thank you. And then, quickly, you mentioned some incremental cost optimization opportunities for 2027-plus. Could you expand on those to the extent you can?
Trevor Howard: Sure. We have a fair amount of general equipment that is under lease—either where we are operating it or where it is a true lease. We are looking at all of our cost structure. The biggest opportunity for us is to integrate a few things that historically we have had others operate for us or have under some kind of capital lease. That is the majority of what we are seeing, and they are very capital-efficient, quick payback projects for us. As Jamie commented, we are in the early stages of transforming, from a data perspective, how we look at our cost structure and optimize there.
That is more about building the framework and foundation in 2026 and starting to see benefits in 2027. In 2026, the immediate focus is buying equipment and insourcing services that we have outsourced.
Brandon B. Bingham: Awesome. Thank you very much.
Operator: Your next question comes from Truist. Please go ahead.
Analyst: Thanks, operator. Good morning, everyone. Thanks for all the color thus far. Jamie, I was hoping to get some thoughts around adding more Gulf Coast exposure in the 2028 to 2030 period. Looking at the strip, with all the egress coming on, Waha should improve and experience better days ahead. What is the rationale for longer-term exposure there?
Jamie W. Welch: Thanks for the question. It is interesting because we have gone from a situation where Waha was a heavily discounted price relative to Ship Channel or South Texas and was disadvantaged, to now where it is outright negative. It is in such a bad place. We think about 2028 to 2030 as follows: this too shall pass—we will get out of the purgatory of negative absolute pricing—but it is our estimation that Waha will remain a discounted price point relative to every other nodal market price in and around Texas. Therefore, the need for premium pricing will remain Gulf Coast or export. Those are your two options. Securing incremental Gulf Coast supply will remain critically important.
Likewise, contracting for incremental export and LNG opportunities is something we are focused on. We start our INEOS contract at the beginning of next year, which we are looking forward to. We will get out of this negative price paradigm, but it will still remain a heavily discounted price point relative to other options. We will continue focusing on the premium options and how we can secure more of it for our customers going forward, because there seems to be an endless demand for that from our customers.
Kris Kindrick: The important point Jamie said was “for our customers.” Our customers want to get out of Waha. The period of 2028 to 2030 is important. We have renewal options on our Gulf Coast capacity in 2031, so it syncs up well with that. The forward says Waha gets better, but the last five years, the forwards have been wrong. We are seeing gas growth out of the basin, and it has been an important differentiator for us. We are going to continue to get exposure in basins other than Waha.
Analyst: That makes sense. As a quick follow-up, can you remind us what your fee floors are on the G&P side, given these curtailments you have highlighted?
Trevor Howard: I am happy to jump in here. We do not have fee floors in our business.
Operator: The next question comes from Jeremy Bryan Tonet with JPMorgan Securities LLC. Please go ahead.
Jeremy Bryan Tonet: I wanted to build on some of the commentary before. It seems like 2026 you are tracking ahead of expectations at this point, but you do not want to lift the guide—you want to see how more unfolds—but you still have 4Q intact, gradually increasing over the course of the year. What does that mean for 2027? Is there any way you can frame how you see the momentum—what type of growth this could generate or a normalized growth for the business at this point?
Jamie W. Welch: Jeremy, you are right to start with caution. You are talking to Trevor, myself, and the management team. This was our second consecutive beat. It followed a series of misses, which we took personally and felt we needed to do better. We are being very cautious and conservative. It is not lost on us that we had a very strong first quarter, and we are hopeful that will shape up for the balance of this year. We will sit with the guide we have until such time as we conclude that changes make sense.
Importantly, on transparency, the incremental PDP base—on average, 120 million cubic feet a day—is 60% of one of our existing cryos on average, and it peaks and declines depending upon the period. There was already a heightened expectation for 2027, which we agree with. We have a lot of benefits flowing through into 2027: NGL contract resets, incremental benefits, the first full year of our sour gas conversion project at King’s Landing. With a higher PDP base and accelerated activity earlier in the year, it sets us up well. It is premature to quantify dollars or percentages of growth, but the sun, the moon, and the stars are aligning for a very strong and positive year post-2026.
Trevor Howard: The other thing I would point you to is that historically we have guided to projects across our entire portfolio being mid-single-digit multiples. If you strip out maintenance, you are looking at $400 million to $425 million of growth capital last year and this year. Looking at 2025 actuals and then adjusting out for the EPIC Crude sale, this year you are looking at double-digit growth. That ties to a reinvestment multiple on the growth capital that we had spent in 2025. Just to provide additional color based on prior comments we have made.
Jeremy Bryan Tonet: That is helpful. One more: some of your peers have talked about a cadence for processing capacity expansions—x plants per year. Any high-level thoughts on what it might look like for Kinetik Holdings Inc. in similar terms?
Jamie W. Welch: We take note of those statements from our competitors. We are probably on the cusp of being big enough to think about what that cadence may look like, but I do not think we are at that point quite yet. We would like to get King’s Landing 2 sorted, done, and behind us, and then we can think about it. We are still exploring the full benefits and breadth of the opportunity set in New Mexico. That will reinforce the perspective on processing cadence and growth needs for the company going forward.
Jeremy Bryan Tonet: Got it. That is helpful. Thank you.
Operator: Your next question comes from John Mackay with Goldman Sachs. Please go ahead.
John Mackay: Hey, team. Thank you for the time. Back in October, you had talked about shut-ins from some oil-directed wells. I just wanted to check in. The shut-ins you are 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 more regular oil-directed activity to be impacted as well?
Jamie W. Welch: You have it right in the context of the impact—Alpine High and more gas-sensitive customers. We have not seen oil-directed customers shutting in. To the contrary, some of the smaller guys, given the current commodity price environment, are looking to accelerate their level of activity. It is a tale of two cities: crude-focused folks are doing cartwheels and backflips, and those that are localized Waha gas-centric sellers are struggling.
John Mackay: Appreciate that. Second one: you keep noting we will 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 T&F recontracting expectations? Alongside this, we would expect NGL volumes to go up. Maybe recontracting gains might not be as high as we could have thought at the end of last year. Could you mark to market that?
Jamie W. Welch: No problem. I think we said on the call in February that the market was even more aggressive than we were anticipating. It is still early days, and we are in this discovery phase as we have communicated. We said we would clearly communicate to the market at the appropriate time. The expectation is you will have even better net realized margins on our part than we previously communicated because of the environment we find ourselves in. It is the antithesis of what you just described.
John Mackay: Fair enough. That is interesting. We will stay tuned. Thanks for the time.
Operator: Your next question comes from Keith T. Stanley with Wolfe Research. Please go ahead.
Keith T. Stanley: Good morning. For the new packages of gas coming on in the summer that boost the second-half outlook, I want to confirm those producers that are bringing on those new volumes have gas takeaway capacity, so they are not sensitive to what is going on with Waha.
Jamie W. Welch: Yes, correct. They have Gulf Coast transport.
Keith T. Stanley: Great. Second question: you have had a good couple of quarters dealing with the Waha issue. How confident are you that marketing gains can continue to offset curtailment losses this year, and what is the risk around that? I assume it is if pipes you have FTE on experience unexpected downtime. Can you frame how you are thinking about risks to continuing to manage this year?
Jamie W. Welch: From an overall dynamic, we have multiple FTE arrangements on multiple pipelines. The overall reliability we have seen remains high, and it would have far-reaching consequences if there were unexpected issues. We are not anticipating any. There is a very regular cadence of maintenance in the fall and spring, communicated clearly to shippers. As far as managing is concerned, we have been looking at the spread differential between Waha and Houston Ship Channel. We have some hedges in place that mirror the expected capacity profile. We see more dislocation in Waha in the spring and fall during maintenance seasons when there is curtailment of capacity when pipes come down for days or maybe a week.
We have been able to manage it. We feel confident we will be able to manage it. We have managed it through the first quarter, through April, and May as well. We are finding our sea legs as far as managing this exposure, even though it is very volatile. Trevor and the team have done a really good job.
Trevor Howard: I would also say part of the risk is testing new lows. This company has done a very nice job managing 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 also in October, where you start to see $8, $9, almost $10 negative Waha. Being totally candid, the risk is whether you go and touch new lows we have not seen, like minus $15 per MMBtu.
Given the setup of Hugh Brinson starting to have some deliveries in the third quarter, Blackcomb coming online in the fourth quarter, Hugh Brinson reaching full in-service, and GCS coming online this summer, I think the risk of us touching new lows is quite low. The commercial team has done a nice job of playing offense, learning from customer feedback, and migrating the portfolio to primarily Gulf Coast sales, which is important and a long-term strategy to help insulate us from the shut-ins we have seen. There is a lot of wood to chop, but the team’s initial work has been strong, demonstrated over the last two quarters of performance.
Keith T. Stanley: Thank you. That is helpful detail.
Operator: Your next question comes from Jefferies. Please go ahead.
Analyst: Good morning, everyone. It is Rob on for Julien. Just one for me. I think you alluded in your prepared remarks to being a bit less hedged during the spring. Waha has been even more discounted in April and May. Any reason you would not expect to perform as you did in 1Q, if not better, in the second quarter?
Jamie W. Welch: Rob, thanks for the question. Let us not get ahead of ourselves. We feel confident and good about where we are. Your statement is correct that April and May have been fairly negative from a Waha pricing standpoint. We will take each day and each month as we find it, and we will continue to build upon our financial base and aim to outperform.
Analyst: Understood. Thanks for the time, everyone.
Operator: Your next question comes from Saumya Jain with UBS. Please go ahead.
Saumya Jain: Hi. Good morning. Thanks for taking my question. 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 infrastructure investments to capture more gas residue? Could you detail what sorts of infrastructure investments are also needed on the gas residue side to expand that opportunity?
Jamie W. Welch: This is Jamie Welch. As far as infrastructure and capital in New Mexico, 70% of our budget is allocated to New Mexico versus Texas. A lot of it is related to the AGI sour conversion project being one of the larger ones, and the completion of the ECCC pipeline. You have some long-lead items in relation to King’s Landing 2. On the residue side, we have connectivity to the existing pipeline operators up there—Transwestern, El Paso—and we will have other connections going forward. That is not huge dollars from our vantage point. It is all encapsulated within the CapEx we gave and have listed in our prepared materials.
If I were to think about dollars, it is roughly $320 million versus the overall $480 million midpoint for our guidance.
Saumya Jain: Thank you. Could you comment on any discussions with customers on technologies increasing recovery in the Permian, and if you have seen any notable differences from that already in the Delaware Basin?
Kris Kindrick: We have seen efficiencies. It shows in production data, and from at least our public customers discussing on their calls. A lot of them are reticent to share any competitive advantage because that is part of how they optimize their costs. We are seeing a decrease in days drilled and similar metrics. There has been a trend of improved technologies over time, but nothing specific to a certain customer that we can share.
Operator: We have reached the end of the Q&A session. I will now turn the call back to Jamie W. Welch for closing remarks.
Jamie W. Welch: Thank you, everyone, for your time this morning. We look forward to seeing you in a few weeks at EIC. We wish everyone a great day.
Operator: This concludes today’s call. Thank you for attending. You may now disconnect.
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Kinetik (KNTK) Q1 2026 Earnings Transcript was originally published by The Motley Fool