Earnings Call Transcript - PR Q4 2025

Operator, Operator

Good morning, and welcome to Permian Resources Corporation conference call to discuss its fourth quarter and full year 2025 earnings. Today's call is being recorded. A replay of the call will be accessible until 03/13/2026 by dialing (888) 660-6264 and entering the replay access code 23999, or by visiting the company's website at www.permianres.com. At this time, I will turn the call over to Hays Mabry, Permian Resources Corporation Vice President of Investor Relations, for opening remarks. Please go ahead.

Hays Mabry, Vice President, Investor Relations

On the call today are Will Hickey and James Walter, our Co-Chief Executive Officers, and Guy Oliphint, our Chief Financial Officer. Many of the comments during this call are forward-looking statements that involve risks and uncertainties that could affect our actual results, and are discussed in more detail in our filings with the SEC. We may also refer to non-GAAP financial measures. For any non-GAAP measure we use, a reconciliation to the nearest corresponding GAAP measure can be found in our earnings release or presentation. With that, I will turn the call over to Will Hickey, Co-CEO.

William M. Hickey, Co-CEO

Thanks, Hays. We are excited to discuss our fourth quarter results as well as our 2026 plan this morning. We set records across every key operational metric in Q4, including our highest oil production, lowest D&C cost per foot, and lowest controllable cash cost in Permian Resources Corporation history. Our strong Q4 performance capped off an excellent 2025 with free cash flow per share increasing 18% year-over-year to $1.94 per share. This performance was achieved alongside meaningful debt reduction, demonstrating the strength and consistency of our core operations. We believe 2025 represents a highly repeatable year and a clear demonstration of the strength of our business. As we look to 2026, our focus remains the same: maximize shareholder value through disciplined execution of our highly capital efficient Delaware Basin program. We are proud to lay out a 2026 plan that we expect will continue to drive free cash flow per share growth going forward. Moving into quarterly results, Q4 production exceeded expectations with oil production of 188,600 barrels of oil per day and total production of 401,500 barrels of oil equivalent per day. Our D&C team continued to execute at a high level, reducing D&C cost per foot to $700, resulting in $481,000,000 of cash CapEx for the quarter and $1,970,000,000 for the year. In addition, we delivered leading cash costs supporting strong margins with Q4 LOE of $5.26 per BOE, cash G&A of $0.80 per BOE, and GP&T of $1.18 per BOE. Strong production results paired with low cash costs and CapEx resulted in adjusted operating cash flow of $884,000,000 and adjusted free cash flow of $403,000,000. Lastly, I want to highlight we are increasing our 2026 quarterly base dividend to $0.16 per share, a 7% increase. Since inception in 2022, Permian Resources Corporation has grown its quarterly base dividend at a 40% CAGR, reflecting the company's commitment to delivering a sustainable and growing base dividend. On slides four and five, I just want to highlight how strong 2025 was for Permian Resources Corporation. This marked our third consecutive year of strong operational execution as a public company, building on our previous track record as a private company dating back to 2015. The depth and experience continues to translate directly into results in the field. Including the bolt-on acquisitions we closed during the year, we delivered 5% higher oil production than our original 2025 guidance, with more than half that outperformance coming from improvements in the base business. That speaks to the quality and durability of our underlying asset base. At the same time, the team continued to structurally lower cost. On the drilling side, we increased drilling feet per day by 6% year-over-year by continuing to optimize BHAs targeting in the lateral. In completions, completed lateral feet per day increased 20% year-over-year due to increased simul-frac efficiencies and other improvements. On the operating side, initiatives like our microgrid projects and runtime improvements led to a 3% reduction in LOE per BOE. We also strengthened the corporate cost structure by reducing debt by over $600,000,000, enhancing netbacks through marketing optimization, and holding nominal G&A flat despite a larger production base. All of this directly benefits our 2026 plan, which James will outline shortly. Given the marginal nature of free cash flow in our business, operating as a low-cost leader is a critical part of our plan to increase free cash flow per share over time. Slide six highlights the details of the meaningful progress we have made improving our gas realization by reducing Waha exposure. We laid the groundwork in 2024 with key hires across the midstream and marketing department, and we continued building that capability through 2025. As a result of the agreements we have executed, we expect to sell 400,000,000 cubic feet per day out of the basin in 2026, increasing to roughly 700,000,000 cubic feet per day in 2027 and beyond. Combined with our existing hedge position, this reduces Waha exposure to approximately 10% of total gas volumes in 2026 and improves unhedged gas realizations. Specifically, in 2025, we expect our gas realizations to be roughly a $0.40 discount versus Waha. Through these recent efforts, we now expect to realize a $0.50 premium to Waha this year. With that, I will turn it over to James to walk through our BD efforts and our 2026 guidance.

James H. Walter, Co-CEO

Thanks, Will. Turning to slide seven, we wanted to highlight the continued success of our acquisition strategy. During Q4, we closed on approximately 140 transactions totaling $240,000,000. This particular set of acquisitions was heavily inventory-weighted and added 7,700 net acres, 1,300 net royalty acres, and approximately 70 net locations at attractive valuations. The Q4 acquisitions capped off a great 2025 M&A program; our confidence in continuing to execute on the strategy going forward is as high as ever. We completed approximately $1,100,000,000 of acquisitions during the year, adding about 250 locations and 13,000 BOE per day within our existing operating areas. These 700 acquisitions consist of a large asset deal from Apache in New Mexico, several medium-sized bolt-on acquisitions, and a substantial ground game that totaled over 675 smaller transactions. For the third consecutive year, Permian Resources Corporation acquired more inventory than we drilled during the year, both increasing our inventory lives and enhancing the quality of our go-forward plan. In addition to the 250 high rate of return locations that Permian Resources Corporation acquired through the year, Permian Resources Corporation also added another 200 locations through organic inventory expansion. We believe that our local presence in Midland and our peer-leading cost structure in the Delaware provide a competitive advantage as we pursue transactions that create long-term value for shareholders. Over the next 12 to 24 months, we are confident in our ability to continue to find attractive deals, drive value for investors, and make our business better—just like we have the last ten years. To slide nine. We are excited to discuss our 2026 plan, which is focused on maximizing returns and free cash flow per share through consistent, thoughtful capital allocation and low-cost execution. This plan is a product of significant collaboration across the organization; we want to thank our entire team for the commitment and effort behind it. For the full year 2026, we expect total production to average 415,000 BOE per day and oil production to average 189,000 barrels of oil per day. We expect to spend $1,850,000,000 of CapEx for the year, approximately $400,000,000 of that coming from non-D&C spend. Overall, this plan delivers production in 2026 that is approximately 5% higher than 2025 for CapEx that is $120,000,000 lower. Our development program and well mix will be largely the same as last year; we will continue to be focused on our high-returning Delaware Basin asset, with the New Mexico portion of the Delaware accounting for about 65% of activity and the Texas Delaware accounting for about 30%. We expect our average working interest, 8/8ths NRI, and well mix by zone to be very similar to last year. The combination of the same or better well productivity with lower costs across the board drives meaningfully improved capital efficiency and lower breakevens, which we can go through in more detail on slide 10. As we have been saying for a while now, we are drilling the same wells in the same areas this year as we have the past few years. As a result, we expect 2026 productivity to be in line to slightly better than 2024–2025, which are basically on top of one another. And we continue to see meaningful improvements in our cost structure with our anticipated 2026 cost of $675 per foot, approximately 20% cheaper than we were in 2024. The combination of Permian Resources Corporation’s consistent well productivity and lower operating costs allows Permian Resources Corporation to continue to improve our capital efficiency and deliver a 2026 plan that has 20% higher oil volumes on 10% less CapEx when compared to 2024. Slide 11 can go back to 2023 to highlight the continued execution that has helped drive the outsized investor returns; to a higher level on the next slide. Our sole focus today is on increasing free cash flow per share, creating long-term value for investors. From 2024 to 2026, we have increased oil production by 30,000 barrels of oil per day while reducing our CapEx budget by $250,000,000. Free cash flow per share has grown from $1.13 in 2023 when oil was at $78 to almost $2 per share this past year with oil averaging $65 per barrel, representing a CAGR of approximately 30%. Permian Resources Corporation’s consistent free cash flow per share growth proved strong execution can overcome commodity price volatility and create outsized returns for investors. Finally, slide 12 helps summarize the free cash flow per share growth we have achieved over the past few years. Our team's efforts led to free cash flow per share in 2025 that is 72% higher than it was in 2023. This is what we have our entire team focused on: durable, long-term free cash flow per share growth. What the other two graphs show are: one, that free cash flow per share growth has driven our outsized shareholder return; and two, that shareholder return has occurred without a rerating of our business. So our plan is to keep growing free cash flow per share. We are confident that execution on that plan will drive continued appreciation in our share price with or without a rerating of our multiple.

William M. Hickey, Co-CEO

Thank you for tuning in today, and I will turn it back to the operator for Q&A.

Operator, Operator

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star, then the number one, on your telephone keypad. If you would like to withdraw your question, please press the pound key. Your first question comes from Kevin McCurdy with Pickering Energy Partners. Please go ahead.

Kevin Moreland McCurdy, Analyst, Pickering Energy Partners

Hey, great. Thank you for taking my question. Maybe a strategy question to start. You have had a relentless and very successful focus on free cash flow per share growth over the past few years. But whereas your free cash flow focus has led you to grow volumes, a lot of your peers are trying to grow free cash flow with flat or even declining volumes. What do you think you are doing right that others are missing, or is this just kind of an outcome of inventory quality? And maybe a follow-up on capital allocation. You have a lot of free cash flow coming your way in 2026. The balance sheet is in a great position. Can you talk about how you are thinking about the various uses of cash this year?

William M. Hickey, Co-CEO

I think there are definitely different ways to grow free cash flow per share. You can grow it via the numerator, which has largely been our strategy—both organic and inorganic free cash flow growth over the last couple of years. And you can also grow it through the denominator. That is probably a different business model than we have pursued, but I do not think that makes it wrong. It reflects an opportunity set, inventory quality, and really just the maturity of our business.

James H. Walter, Co-CEO

I think a lot of businesses that are shifting to a reduce-the-denominator buyback-share strategy are typically more mature businesses and more mature basins. For us, we are fortunate to be in the most exciting oil basin in North America that has a ton of running room. You have seen us do more free cash flow per share growth in terms of organic growth and growth through acquisitions. That has been a really good recipe for us. On capital allocation, we had a great slide in our deck, slide 16. We have free cash flow coming in, and our plan is to use every tool we have in the toolkit as the opportunity persists. Capital allocation is something we really pride ourselves on. We have done a great job of that the past decade. We will allocate capital to the opportunities that drive the greatest return over the long term. Obviously, base dividend is first and foremost, and we are proud of our track record of continuing to grow that dividend year in and year out. Beyond that, it depends on the opportunity set. If we have attractive accretive acquisitions, we will pursue those. If not, we are always excited to accrue cash to the balance sheet because this is a cyclical business. Paying down debt and saving dollars for the future has been a great return for us in the past. Finally, when dislocations exist, we are excited to buy back shares. We leaned in heavily for a week or two in April and have not had many opportunities since then. For us, capital allocation is all of the above, and we do not see any need to limit ourselves going forward.

Operator, Operator

Your next question comes from Neal Dingmann with William Blair. Please go ahead.

Neal Dingmann, Analyst, William Blair

Good morning, guys. Nice quarter. James, my question sticking with this a little bit is on the ground game specifically. Just curious how active you all believe you can continue to be on ground game and maybe just M&A in general given a couple things. One, it is pretty notable your peers out there paying record prices for leases, and even the ABS market continues to heat up. So it certainly seems to be a bit of a seller's market out there. You seem to have confidence both on ground game and just external growth overall. Would love to hear where that confidence comes from. And then my second question is on potential for ancillary businesses. Specifically, you have talked in the past—you have got a fair amount of surface acreage. There is potential for you and some other guys in the basin for power deals. And how are you looking at either things like lithium extraction or other byproducts of your produced water?

James H. Walter, Co-CEO

In our ground game, the small blocking and tackling stuff has been remarkably consistent for a decade. As we have grown our position, we have gotten our team in place and the prospects are better; 2025 is probably our best year ever from a ground game perspective. Many of these deals are less subject to market pricing and fluctuations. Think about the ground game and most of the bolt-ons that we have done. Those are one-off negotiated deals sourced through relationships we have in Midland, industry partners, and relationships in New Mexico that go back the better part of a decade. We have been fortunate to find a lot of good values. We pay real prices for high-quality assets—that has always been our business model—but we are still seeing opportunities that make sense and are more insulated from market fluctuations. Regarding ABS and market changes, we have pursued inventory-weighted deals the entirety of our existence. We have stayed away from assets that were a larger percentage of production, higher decline, or things like that. For us, we have not seen a lot of pressure from the ABS market on the type of acquisitions we want to buy because we pursue inventory-weighted deals.

William M. Hickey, Co-CEO

On ancillary businesses, we own 25,000 surface acres across the Delaware Basin. The majority of that is in Reeves County on the Texas side of the basin, and we have a few blockier big chunks that are in opportunistic spots for potential power generation. I am not messaging this as near term or something to announce in the coming quarters, but it is something we are exploring to understand the market. There are data centers coming to West Texas on ranches nearby ours, which could be a useful case study. For us, it is a balance. The surface acres are also key to our day-to-day oil and gas operations. We have water wells, SWDs, recycling pits on them, and we use them every day. We are trying to balance potential monetization or partnership versus leveraging them to reduce upstream costs.

Operator, Operator

Your next question comes from John Freeman with Raymond James. Go ahead, John.

John Christopher Freeman, Analyst, Raymond James

Thanks. Good morning, guys. Given the continued cost reductions that you all continue to see, obviously from a return perspective, you all could always choose to flex activity higher. When you are going through the budgeting process, is there a reinvestment rate that you are targeting when setting the budget, and what impact does the geopolitical-driven volatility we have seen in oil this year play into that thought process?

James H. Walter, Co-CEO

We do not target a specific reinvestment rate. Many factors factor in, and macro is certainly one of them. We are typically focused on growing production when we see free cash flow accretion in a 12 to 18 month period, which requires wells with quick payouts and high returns. You could argue we are in that environment today, but we are conscious of the macro environment. As we headed into 2026 there was a risk of a meaningfully oversupplied market. Even with wells that meet our criteria, it felt prudent to be cautious on growth in planning for 2026 until we have more certainty on macro and longer-term oil prices. We have the inventory base and the wells that would justify growth, but we are being patient.

John Christopher Freeman, Analyst, Raymond James

Great. And my follow-up: you added 200 locations last year through organic inventory expansion. It has been topical with some of your Permian peers talking about increased exploration efforts, looking at some new benches or areas. Anything else that you are looking at that has you intrigued right now on newer areas or benches?

William M. Hickey, Co-CEO

Most of our exploration is better understanding what we have up hole and down hole within the 4,000-foot column that is the Delaware Basin. Our development plan in 2024–2026 has been consistent: developing Bone Spring down through the Wolfcamp XY or top of the Wolfcamp. We have added some Avalon and deeper Wolfcamp to development plans based on offsets. That is the type of exploration we are doing. Given our vast position today and confidence in existing inventory quality and duration, it is more about what we have on our existing footprint. The organic additions of inventory were largely that type of work. As you move further north away from the state line, we did not typically take credit for Avalon. We watched others add Avalon, and we added it to some of our plans successfully and have added Avalon to the inventory stack. Same thing with Wolfcamp C or D nomenclature.

Operator, Operator

We now have a question from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Michael Hanold, Analyst, RBC Capital Markets

Thanks. Good morning. On consistent well performance—it is impressive and helps drive things forward better than anticipated. A big part of that is how you guys have really reduced D&C cost quite a bit over the last couple of years. Can you give us a sense of additional levers you can pull? Can you continue to move that D&C cost per foot down? And, agnostic to wholesale service costing, if you want to add commentary there, please do.

William M. Hickey, Co-CEO

We achieved progress by cutting days on the drilling side and leveraging completion efficiencies as the industry moved from single-well to zipper to simul-frac and recycling water. Going forward, there is more juice to squeeze on the drilling side. Given our cost structure in the Delaware, the comparator is Midland Basin operators. If we are at $675 per foot in the Delaware, there is a $100-plus per foot delta between our well cost and Midland Basin well cost. The biggest delta is on the drilling side. If we average roughly 13 days spud to rig release on a two-mile well, Midland Basin is five-plus days faster, and at a $100,000 to $125,000 a day spread rate, that is another $500,000 to $700,000 per well. That is where we are focused. We cut drilling times 6% year-over-year; last year even more. It is an all-of-the-above approach; no silver bullet, but reducing days on the drilling side likely means increased ROP in the lateral.

Scott Michael Hanold, Analyst, RBC Capital Markets

Got it. Thanks for that. My follow-up question is on M&A. Can you give us a sense of what you are seeing in the M&A market in terms of ground game and larger stuff right now? And I am really interested in state and federal lease sales—what is your expectation there, and how competitive is that? Do lease sales present a better opportunity, or are those much more competitive versus ground-based returns?

James H. Walter, Co-CEO

The deal pipeline feels strong. Our ground game is building momentum; the opportunity set is widening and accelerating. We are seeing attractive $500 million to $1 billion assets like Oxy’s Beryl Draw and Apache’s New Mexico exit, and we are starting to hear rumors and see signs of larger packages coming. There has been a ton of consolidation in the Permian; we may be on the front end of larger consolidators having divestitures that make sense on the backside. Historically, largest companies consolidate and a deconsolidation wave comes a few years later. We may be entering a phase of that in the next couple years, which adds to the opportunity set. Regarding federal lease sales, it is good the administration has pushed those out. Historically, those lease sales are really competitive—anyone can bid online—so they tend to be more expensive than most acquisitions we look at. We have not been as competitive there as in other channels. We have bought in New Mexico state, Texas state, and federal sales when we had an edge—strategic or information— which does not apply to all of them. We participate when we have that edge, but they tend to be pretty competitive.

Operator, Operator

Your next question comes from Zach Parham with JPMorgan. Please go ahead.

Zach Parham, Analyst, JPMorgan

Question. James, you mentioned this in your prepared remarks, and it is also in the slide deck, but you have a well cume plot comparing the last few years. And 2026 expectations are flattish to slightly up on a lateral-foot adjusted basis. Can you talk about what is driving that expectation for slightly better productivity year-over-year? Is that different than what we are seeing across the industry? And as a follow-up, you mentioned drilling the longest lateral in company history in 4Q, around 17,000 feet. Is that something you are considering doing more of, and can that help drive costs lower?

William M. Hickey, Co-CEO

We are not precise to the half-percent, but the general point is our development plan has been very consistent—co-develop benches that need to be co-developed and develop those same benches methodically across our position. 2025 was no different than 2024, and 2026 is no different than 2025. That consistency underpins our free cash flow per share growth—holding well productivity flat while cutting costs more than oil prices hurt you. On extra-long laterals, a couple years ago I said two miles is the optimal length in the Delaware Basin for reasons like total fluid volumes and flowing back three miles’ worth of fluid up five-and-a-half-inch casing delaying barrels in a way that offsets D&C savings. Conceptually true, but probably not perfectly true. The optimal lateral length may be two and a half now. As we develop our position, if we have a four-mile fairway, we will drill two two-mile wells. Five-mile fairway, two two-and-a-half-mile wells. Six-mile fairway, it is a debate: two three-milers or three two-milers. We have proven we can drill two-, three-, and even three-and-a-half-mile wells. The question is what generates the highest rate of return: dollar-per-foot savings on one end but delayed peak production on the other. At that point, it is a math problem.

Operator, Operator

Thank you. You now have a question from Derrick Whitfield with Texas Capital. Please go ahead.

Derrick Whitfield, Analyst, Texas Capital

Good morning all, and congrats on an exceptional year-end. With my questions, I wanted to lean in on the consistency of well performance you highlight on slide 10—it has been remarkably consistent over the last three years and a clear standout. As you look forward in time, how comfortable are you in continuing to generate that level of productivity? It feels like the depth there is good for five years or so. And as a follow-up, while acknowledging you are not highlighting surfactants or driver-based production optimization on today’s call, could you speak to where you are in assessing its potential positive impact to production?

William M. Hickey, Co-CEO

I can say with real confidence that for the next four to five years, this is what you should expect to see. Past that, it is uncertain what other benches we add or what the M&A machine supplies once you get past the end of the decade. As we build schedules and work with planning, we can continue to maintain this for quite some time. On production optimization, we have tried mixes of surfactants and acids on existing producing wells, typically around first ESP failures. Results are mixed. Some have been wildly successful—doubling or tripling existing production rates; some have a muted response. I would lump surfactants—bringing back common fracture-side surfactant from 2017–2018 with new tech today—along with things like lightweight proppant. Five to ten years ago people pumped man-made lightweight proppants; now with pet coke and other tests, there is a big lightweight proppant push. I would even include EOR in that bucket. There is more focus on increasing recoveries and productivity than ever. I am not willing to pick the winner, but I am confident there will be big wins quickly adopted across the industry. For companies like Permian Resources Corporation with great assets in great basins, it will be a big tailwind. The last three or four years saw huge effort cutting cost out of the system. I would not be surprised if the next three or four years is an equal effort on adding barrels—which can be a much bigger difference than cutting costs in the long term.

Operator, Operator

We now have a question from Neil Mehta with Goldman Sachs. Neil, please go ahead.

Neil Singhvi Mehta, Analyst, Goldman Sachs

Yeah. Good morning, Will, Guy, James. Question on the gas macro in the Permian. On slide six you talk about how you have been managing through your gas marketing portfolio and have mitigated a lot of the near-term local price risk. Two questions: What is your perspective on how Waha evolves over the next couple of years? And how are you managing through this period of commodity softness until we get to the other side? And as a follow-up, on slide 12, I like the free cash flow per share framework. The biggest risk with a near-term FCF/share framework is underinvestment. How do you manage the business on this framework over the long term, and what are the pitfalls?

James H. Walter, Co-CEO

This year, forward curves and broader consensus indicate there is potential for challenges in 2026 depending on how the winter finishes and what weather and interruptions—planned and unplanned—look like. It could be a bumpy road. As you get into 2027 and beyond, without an unexpected step change in Permian gas growth, we could be close to having the right pipeline takeaway capacity as a basin to mitigate some or all of the volatility we have seen at Waha the last couple of years. For Permian Resources Corporation, we are pretty well insulated from Waha volatility this year and going forward. We have made a tremendous effort to get better in gas marketing and feel like we have gotten there. As you can see on slide six, 90% of our gas this year will price either hedged at attractive Waha prices or at non-Waha destinations. Same with 2027. This year may be challenged more broadly, next year should get better, and we are in a fortunate position after a lot of hard work. On the FCF/share framework, when we say we are focused on free cash flow per share, that is over the very long term—not single years and certainly not quarters. Our goal is to do what we have done on slide 12 for the next five, ten, twenty years. You cannot underinvest and generate that kind of growth over the long term. There are different ways to focus on FCF/share. Where our business is today, it is more numerator-focused than denominator-focused given our opportunities to reinvest organically and grow, and inorganically through acquisitions. The right way to evaluate us is to look over longer-term periods and not focus overly on this year or next, or this quarter or that quarter. Look at the arc of FCF/share growth over the long term.

Operator, Operator

You now have a question from John Abbott with Wolfe Research. Go ahead, John.

John Holliday Abbott, Analyst, Wolfe Research

Hey. Good morning, and thank you for taking our questions. The question is on growth. You are sort of in this yellow light scenario, to use one of the phrases from a peer. We could see a more constructive environment in the second half of the year or into 2027. As you look at your crystal ball, what is the likelihood that you could start to grow in 2027, and when would you make that decision? And given inventory in hand and ground game, can you remind us on the extent you are willing to grow over a multiyear basis?

James H. Walter, Co-CEO

We are flat over the course of the year from Q1 to Q4 in this environment, but our production is 5% higher in 2026 than 2025. That is probably a yellow light. For a business of our size with a nimble operating team and lean culture, it does not take much to return to a more growthy scenario. We want to be confident in the macro and not get out ahead of it. We will look for real confidence that there is a better supply-demand balance that needs our barrels. Growth depends on macro, oil price, and service cost environment. Historically, when we have grown closer to 10% per year—that starts to feel higher—but something in the mid- to high-single digits in an attractive reinvestment and capital deployment environment is something we can get excited about and have the inventory base to prosecute.

John Holliday Abbott, Analyst, Wolfe Research

And then a follow-up: you are about 50% hedged for oil this year. How are you thinking about hedges as you think to 2027? If you have a more positive oil environment, how are you thinking about hedges?

Guy M. Oliphint, Chief Financial Officer

We are a little bit less hedged than that for 2026. Our targets are 30%, 20%, 10%—year one, two, and three out. The macro does not weigh too much into how we hedge. We think those targets make sense, and hedging still makes sense despite our strong balance sheet because the liquidity from hedges provides capital to deploy in a downturn. If we take hedge proceeds when there is $50 oil, there are likely buybacks to do, acquisitions to make—those sorts of things. Where we try to be flexible is leaning in during periods of volatility. In the last year those periods have been short, so we hedge into those opportunistically, but we are not going to programmatically hit our targets at lower oil prices than we think are mid-cycle just to force it. We have done a good job of getting to those targets despite that. It fits how we think about capital allocation, particularly in a downturn.

Operator, Operator

Thank you. The next question comes from Philip Jungwirth with BMO. Go ahead.

Phillip J. Jungwirth, Analyst, BMO Capital Markets

You mentioned earlier some of the historical consolidators in the Permian now looking to divest assets, and we saw news reports of one such deal in the last week. Given how much you have grown the company over the last couple of years, is there an upper limit on transaction size, and remind us of balance sheet parameters when you consider larger-sized deals? And as a follow-up, you guided to a $0.25 to $0.75 premium to Waha in 2026. Based on the FEP and the marketing agreements, how should we think about 2027—premium to Waha or discount to Henry Hub?

James H. Walter, Co-CEO

We have ample liquidity, low leverage, and are hopefully on the cusp of achieving investment grade status. The limiter will not be access to capital; it will be our comfort with leverage. We have the capacity to do $1 billion, $2 billion, or even $3 billion of deals over the next year or two within our leverage comfort zones at $60 or $65 oil. As you spend more dollars, you need to be pickier to ensure transactions are the right ones. We have the horsepower to do whatever comes, but we are not going to lever up or risk the business to pursue near-term free cash flow accretion.

Guy M. Oliphint, Chief Financial Officer

If you look at that graph, the significant majority—90% plus—of our exposure in 2027 is HSC or DFW. So we will be talking about pricing relative to those benchmarks, which you can convert to relative to Henry Hub. Next year we will not be guiding or thinking about gas on a Waha basis; we will think about it on a Gulf Coast/Texark basis.

Operator, Operator

Your next question comes from Josh Silverstein with UBS. Go ahead, Josh.

Josh Silverstein, Analyst, UBS

Hey. Thanks. Good morning, guys. With the additional FC capacity coming to the portfolio next year, does it change the development strategy at all? Do you drill in areas with similar oil flow rates but with greater gas mix? And on value creation, can you talk about the royalty opportunity for Permian Resources Corporation? You are now over 100,000 net acres. What is the royalty percent of your total production, and would you consider putting this into another vehicle?

William M. Hickey, Co-CEO

No change. We will benefit from tailwinds of a better gas price on the roughly 700,000,000 of residue gas we sell today, but we will not allocate capital differently because of that. Oil still drives the day based on our assets.

Guy M. Oliphint, Chief Financial Officer

We have stayed away from giving explicit stats about our royalty business to date, and that still makes sense given its maturity.

James H. Walter, Co-CEO

We have thought about alternatives. We have an excellent royalty business, and it fits really well within our upstream business. Allocating capital to higher NRI and royalty-weighted assets has been an important part of our capital efficiency story the last few years. We love having it in the business. If we were convinced that business could create more value as a standalone or subsidiary-type business, that is something we have been thinking about and will continue to think about. We just have not had the right level of conviction around that value-creation story today, but we will keep evaluating in the coming months, quarters, and years.

Operator, Operator

We now have a question from Marian Marney with Roth. Marian, please go ahead.

Marian Marney, Analyst, Roth

Hey, guys. Wanted to see if you could talk a little about cadence on the year. In terms of capital or production, historically you have been a little more front-half weighted on CapEx. Is that something we are going to see again in 2026? And on production, your oil is roughly flat with 4Q. Was there any downtime in 1Q from storms and then a rebound in second quarter? Any moving parts there? And I was hoping you could also talk about the non-D&C spend—if I heard you right, you said around $400,000,000 this year. That seems like a bit higher percentage than years past. What is the focus there and what do you plan to achieve with that? Finally, on cash taxes—hardly anything this year—what is the outlook? Does that start to pick up in 2027, or more of a 2028 thing?

William M. Hickey, Co-CEO

Production should be flat throughout the year. The team worked hard to keep the overwhelming majority of our production online during the storm; production will not see a Q1 dip due to the storm. On CapEx, it is relatively equally weighted throughout the year. You may see some fluctuations intra-quarter, but first half/second half is relatively balanced. On non-D&C spend, we have not seen the same amount of deflation as in other parts of the business. It includes a lot of tanks, vessels, steel, compression—things that have been less deflationary.

James H. Walter, Co-CEO

The efficiency gains on D&C have been extraordinary. Teams responsible for other CapEx components have done a good job, but that has been more about stemming tariff-driven inflation. Over time, as the business matures, we are confident we can reduce spending on infrastructure and other CapEx, but this year it makes sense that you have not seen the same reduction for the reasons Will outlined.

Guy M. Oliphint, Chief Financial Officer

On cash taxes, our guidance is consistent with what we have discussed. We thought 2026 would be low and 2027 would be low based on strip, which has played out. Based on where we are today, we do not see ourselves being a full cash taxpayer until 2028 or beyond.

Operator, Operator

Your next question comes from Noah Hungness with Bank of America. Noah, please go ahead.

Noah B. Hungness, Analyst, Bank of America

I wanted to start on the balance sheet. You increased accounts receivable by $20,000,000 quarter-over-quarter. What drove that, and would you expect that to unwind through 2026? And on average lateral length—you have continued to increase it. This year you are going to be at 11,000 feet on average. Do you think there is further upside to get to two and a half miles, and if so, what would that do for D&C per foot costs?

Guy M. Oliphint, Chief Financial Officer

We have seen AR and AP grow—so working capital is pretty constant even though those gross balances are up. As our business scales, those balances correlate with that. There was not a change in total working capital or a draw—just balances increasing as the size of the business grows.

William M. Hickey, Co-CEO

On lateral length, on the margin there are a few places in the existing position where, now that we are comfortable going longer, we can. For the most part, we have done the work and set it up for how we are going to drill it. Most units are set up for two miles, two and a half, or in some cases three. Where you could see change over time is as we buy and core up new assets. The land team has been told the ideal lateral length is probably closer to two and a half than two, and they will do the work accordingly to extend laterals further. If you added an extra roughly 2,500 feet, the D&C per foot reduction only helps—likely low double-digit dollars per foot reduction, say $20–$25 per foot, as a rough guess.

Noah B. Hungness, Analyst, Bank of America

Okay. Yeah. No. That is really helpful. Thanks, guys.

Operator, Operator

As a reminder, if you wish to ask a question, please press star followed by the one. Your next question comes from Paul Diamond with Citi. Paul, please go ahead.

Paul Michael Diamond, Analyst, Citi

Good morning. Quick one on reserve replacement. You have done well replacing drilling locations over the last few years. Given the geographic focus up in the Northern Delaware, should we expect the same? Is the intent to replace more up there, or is that just where recent deals have been? And as you approach investment grade across all three agencies, how do you think about any potential shift in your financial strategy on the other side—is it moving you at all, or business as usual?

James H. Walter, Co-CEO

2025 was more New Mexico heavy in inventory acquisitions; that is largely opportunity-set driven. We love our Texas assets. We did a pretty inventory-heavy acquisition in Texas in 2024 with the Beryl Draw transaction; that was a strong deal. Generally, there is likely more inventory available and likely to come for sale in New Mexico than in Texas over the next five years, so more likely to do deals up there than in Texas, but we are agnostic—we would do more in Texas if the right deal came along. It depends on what is for sale and what we can get at a price that creates value for shareholders.

Guy M. Oliphint, Chief Financial Officer

On investment grade, why we are focused on it fits with our strategy. We want to reduce our cost of capital and have long-term capital availability. From a timing perspective, we have been at investment grade credit metrics for a long time. Our financial policies have conformed to investment grade policies, and we have built the business quickly but consistent with those policies. It has clear benefits going forward, and we think we meet the criteria today.

Paul Michael Diamond, Analyst, Citi

Understood. Appreciate the time. I will leave it there. Thank you.

Operator, Operator

There are no further questions, so I will turn the call over to James Walter for closing remarks. Please continue.

James H. Walter, Co-CEO

Thank you. Having gotten off to a great start for 2026, our primary goal remains the same: to maximize shareholder value over the long term by growing free cash flow per share. We expect 2026 and the years to come to look a lot like the past few years. And to do that, we plan to continue to build on our track record of delivering consistent results with the lowest cost structure in the Delaware Basin. Thank you to everyone for joining the call today and following the Permian Resources Corporation story.

Operator, Operator

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.