管理層發言
Good morning and welcome to the Permian Resources First Quarter 2026 Earnings Conference Call. Today's call is being recorded and a replay of the call will be accessible until May 20, 2026, by dialing (800) 770-2030 and entering the replay access code 1442298, or by visiting the company's website at www.permianres.com. It is now my pleasure to turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for opening remarks. Please go ahead.
Thank you, Amy, and thank you all for joining us. On the call today are Will Hickey and James Walter, our 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.
Thanks, Hays. Q1 represented another quarter of strong operational execution, delivering free cash flow per share of $0.60, the highest in PR history. In addition, we set records on both drilling and completion cost per foot, continue to deliver peer-leading controllable cash cost and accelerated oil production volumes in response to higher oil prices in March. The current market volatility reinforces what has always been core to the Permian Resources strategy: maintain a peer-leading cost structure, stay singularly focused on the Delaware Basin — the best onshore shale basin in the U.S. — and preserve flexibility as market conditions change. Periods like this give us an opportunity to demonstrate our team's ability to react quickly to create long-term shareholder value. We don't know where the market is headed but we are excited about our position and the flexibility we have to continue to capitalize on opportunities as they emerge. Turning to the quarter. Q1 production exceeded expectations with oil production of 192,000 barrels a day and total production of 413,000 barrels of oil equivalent per day. Production outperformance was driven by better-than-expected results from recent wells and significantly reduced downtime in March due to picking up additional workover rigs as a result of higher prices. In addition to wins on the production side, our D&C team continued to drive down cost. We reduced D&C cost to approximately $685 per lateral foot with both drilling cost per foot and completion cost per foot setting new company records. On the drilling side, we delivered the fastest well in company history, averaging over 2,500 feet per day, and delivered our longest quarterly average lateral length in company history, with roughly one-quarter of our wells coming in over 2.5 miles. On the completion side, we achieved record recycled water utilization rates of approximately 70%. This not only lowers completion cost but also reduces LOE, and it is something you'll continue to see us focused on going forward. On the production side, the team installed four microgrids in the quarter, eliminating over 25 generators and reducing electricity cost on the associated well sites by roughly 30%. I also want to recognize the field team's response to January's Winter Storm Fern. We navigated the storm with minimal impact and recovered to production quickly. That kind of execution is a credit to our team in the field who runs our operations every day. Controllable cash costs came in well within our 2026 guidance with LOE of $5.19 per BOE, GP&T of about $1.36 per BOE and cash G&A of $0.77 per BOE. To wrap it all up, strong production performance, combined with further extending our Delaware Basin cost leadership, resulted in record free cash flow of over $500 million for the quarter. Turning to natural gas. We continue to benefit from our improved natural gas portfolio with the largest impact still ahead of us in 2027 and beyond. During Q1, we saw material weakness in Waha gas pricing. Despite this market backdrop, in Q1 our realized natural gas price, including hedges, was $1.33 per Mcf, a $2.44 premium to Waha during the quarter. Notably, roughly half this uplift is from firm transportation agreements that we entered into over the last few years with the balance from existing natural gas hedges. Today, we have approximately 400 million cubic feet a day of firm transportation to Gulf Coast and DFW markets, growing to over 700 million cubic feet a day in 2027 and beyond as the full impact of our long-haul agreements comes online. Longer term, with 1 Bcf a day of gross production and an attractive end-market portfolio, PR is well positioned to participate in the growth in U.S. natural gas demand. With that, I'll turn the call over to James.
Thanks, Will. Turning to Slide 7. We wanted to emphasize a major milestone that our entire company is excited about and proud of. We received our second and third investment-grade ratings and are now officially an investment-grade company from all three major agencies. This is a reflection of the financial philosophy that has been a core tenet of our business since the beginning. Investment-grade status lowers our cost of debt and ensures access to capital across cycles. We continue to prioritize balance sheet strength and have used our robust free cash flow to reduce absolute debt by approximately $1.2 billion since the beginning of 2025. It's important to note that our capital allocation framework does not change in this environment, but it does allow us to prioritize capital to the uses that we believe will generate the highest risk-adjusted long-term returns. The base dividend is our first priority and we remain committed to consistent long-term growth. Beyond that, our priorities in the current environment are debt repayment, accruing cash to the balance sheet and continuing to pursue accretive acquisitions. The strength of the business is that we do not have to choose between only one or two capital allocation levers. We can lean into whichever one creates the most long-term value at any given moment. As shown on Slide 7, we believe that alignment between management and shareholders is critical to creating long-term value in oil and gas. It is our belief that Permian Resources has a strong investor alignment as any company in this sector. All of our employees receive common equity as part of their annual compensation. Officer compensation is heavily weighted towards equity and performance shares. Finally, co-CEO compensation is entirely performance-based with Will and I receiving no cash salary and no cash bonus. I'm probably most proud of our significant employee ownership. In total, PR employees own roughly 7% of the company, representing over $1 billion in equity value, creating the best possible alignment with shareholders. Slide 9 lays out how the business is operating in today's environment and how we are thinking about the rest of the year. Our priorities today are straightforward. In Q1, our focus was on accelerating near-term barrels by increasing high-return workovers and maximizing run time. We roughly doubled our workover rig count from January to March, which drove approximately half of our production beat for the quarter. Looking ahead to Q2, we expect to further accelerate production by continuing to run an elevated workover program and by taking steps to accelerate additional POPs into the quarter. Our team in the field is doing everything they can to accelerate barrels in this higher price environment. As a result of both higher workover counts and more turn lines in the quarter, we expect production and CapEx in Q2 to be modestly higher than Q1. For the second half of the year, we're in the fortunate position of having maximum flexibility to respond to an uncertain macro environment. If crude prices remain strong, we would expect to come out at the high end of both our production and capital ranges. We will do so with the existing rigs and equipment we have today. Conversely, if conditions were to soften materially, we would expect to reduce activity and come at the lower end of both our production and capital ranges. Our activity levels and growth continue to be driven by the same principles that have always informed our investment decisions, which is maximizing free cash flow in the near term, midterm and long term. Importantly, we expect any range of these outcomes to generate higher free cash flow in 2026 than our original guidance. Turning to Slide 10. We want to conclude by reminding our investors that PR's business plan remains the same. Every day, our focus is on driving long-term free cash flow growth, which we believe is the foundation of durable value creation in oil and gas. Since we became a public company in the middle of 2022, Permian Resources has delivered the highest free cash flow per share growth of any E&P company. In 2023, our first year as a public company, we generated $1.13 per share in free cash flow at an oil price of $78. In 2024, we grew free cash flow per share by nearly 50% to $1.64 at lower prices than the prior year. In 2025, we grew free cash flow per share from $1.64 to $1.94, representing nearly 20% free cash flow per share growth at an oil price that was more than $10 lower than the prior year. We think it's important to be very clear how we have grown free cash flow per share. We've done so by doing three things consistently over that period. One, by being the lowest cost operator in the Delaware Basin, continuing to drive D&C efficiency and cost reductions. We have averaged a greater than 10% per year reduction in D&C every year since 2022. Two, by using our high-quality, long-life inventory to organically grow production and return to macro-environment-justified growth. We have averaged greater than 10% annualized growth since inception. Three, by pursuing high-quality accretive acquisitions that make our business better and enhance our ability to grow free cash flow per share over the long term. We have acquired over $1 billion in high-quality assets each of the past three years. The combined effect of pulling all three of these levers year in, year out is that we have grown free cash flow per share at a 30% CAGR over the past three years despite a market where the average oil price declined every single year. The emphasis on each of the three pillars that drive our free cash flow growth may change from one year to the next based on the macro environment and opportunity set, but our business model remains the same, as does our expectation that we can continue to generate outsized free cash flow per share growth, which will result in correspondingly high returns for our investors through the cycles. Thank you for tuning in today. And now I'll turn it back to the operator for Q&A.
分析師問答
Your first question comes from the line of Scott Hanold with RBC Capital.
I was wondering if you could talk through some of the dynamics of pulling forward some of the production into this environment. Obviously, it sounds like a lot of workovers occurring. How many workovers do you have? Is that something that's going to persist mostly through 2Q and then beyond that, is it just organically pulling forward completions? At the current pace, how many more completions could you get into this year?
The plan today with oil above $90 on a WTI basis is that we're doing everything we can with the existing equipment to accelerate TILs and accelerate barrels into this constructive oil price environment. Workover rig counts doubled. We have gone from roughly 30-40 workovers a month to something closer to 70-90 a month. Long term, you end up working through your backlog and at some point that normalizes out where you work over any well that makes sense when it goes down. At $90-$100 oil, many more wells make sense to work over quickly than at, say, $50 crude. We are getting faster and more efficient every day. We saw a step change in Q1 and continue to show efficiency improvement on both the completion and drilling sides. If you combine faster operations with reducing overall cycle time between drilling and completion, we have the flexibility to accelerate TILs beyond our original base plan using the equipment we're running today. We are maintaining flexibility and may change activity as the market changes. The general plan is to accelerate within the confines of the equipment we operate today, not by picking up additional rigs.
My follow-up question is about cash deployment. With the strip having come down at the front of the curve over the last couple of days but still healthy, when you look at your free cash flow build through the year, it won't take too long into 2027 before net debt could be zero. Could you give us a sense of how you think about utilizing that cash? Are you willing to build cash for black swan events or pursue M&A? Or how would you balance those options?
We've always been comfortable running the business with leverage because it can enhance equity returns. Referencing our capital allocation framework on Slide 7, we constantly evaluate the landscape to see which reinvestment opportunities will drive the highest rate of return for shareholders. That could be share buybacks, debt repayment and accruing cash, acquisitions or raising the dividend. We could go to zero debt in certain scenarios, but it's less likely because we've consistently seen attractive reinvestment opportunities across the business that outcompete cash build. For us, it's about optimizing around the best risk-adjusted return for our cash flow and dollars. There could be scenarios where debt repayment to zero makes sense, but the opportunity set in the Delaware has been so robust historically that cash redeployment into the business has often been the superior choice.
Your next question comes from the line of Neal Dingmann with William Blair.
Nice quarter. My first question is on future activity. Specifically, is activity constrained at all by power supply? And how much is activity influenced by negative Waha pricing? I heard about pre-flowing conversations that might improve Waha, so I'm wondering around power and negative gas prices.
Short answer: no. Activity is not constrained across our position. We are allocating capital as we see fit. Power is less significant, but negative Waha is a meaningful input into our returns calculation. Gas prices matter, crude prices matter and service costs matter. In our framework, we're willing to grow when returns are great and paybacks are short, and be more of a low-growth or hold-flat business when returns are weaker. Generally speaking, Waha may dictate some activity decisions, but we feel unconstrained and are allocating capital appropriately.
On Waha, incremental growth in a meaningful way is weighted toward the middle to back half of the year where we expect Waha prices to improve and ultimately be resolved in the late third or fourth quarter. We don't think Waha will meaningfully dictate plans over the next couple of years; we expect resolution in 2026 as we see it.
My second question is on capital allocation specifically. Given the pristine balance sheet, does capital spent on acquisitions during any quarter influence what you might pay out to shareholders that same quarter? Should we assume shareholder returns are solely an economic decision based on macro variables, or are there other influences?
We allocate capital to whatever we believe will generate the best long-term returns. We constantly weigh acquisitions against other uses. If we do more acquisitions, that accrues less cash and could impact dividend trajectory in the near term. However, the acquisitions we pursue are typically very good for the business and bolster the longer-term base dividend trajectory. We're always pitting alternatives against each other and deciding what makes most sense for the environment we see and where we think the world is going.
Your next question comes from the line of Neil Mehta with Goldman Sachs.
Good quarter. Building on the M&A comments, do you feel PR is well positioned to be active in the market as it potentially becomes more active, especially as the A&D market evolves?
We said in February that it looked like the Delaware Basin market would be active this year, and that's played out. We're seeing more deals for sale than in recent years, many of them in the Delaware and many higher quality. We are well positioned to take advantage at the right price. Our lowest cost structure in the Delaware and Midland-based operational knowledge give us a differentiated advantage. We have a strong base business, so we will only pursue deals at the right prices and where we're highly convinced they make our existing business better.
Can you describe what you're doing on the D&C side to keep momentum going on speed and costs?
This is ingrained in our culture and operations. We're optimizing BHAs to increase ROP in the lateral, reducing bit trips to move toward one-bit runs, and pushing lateral lengths — 25% of our wells were over 2.5 miles this quarter, which helps costs. Our target this year was $675 per lateral foot. We ended last year near $700 per foot and chopped it to $685 in Q1. Efficiencies are on track to achieve the target. Any headwinds from this point forward would likely be inflation-related, and fortunately we haven't seen much of that yet.
Your next question comes from the line of John Freeman with Raymond James.
On the ground game, you're still doing around $200 million a quarter, but the number of transactions fell to about 40 deals this quarter versus the 150-200 annualized run rate previously. Does that indicate a change to bigger, lumpier transactions, or is it normal fluctuation?
That's an observant question. I think it's normal fluctuation. We're focused on absolute dollars and actual absolute value creation. Forty deals in a quarter is still a strong pace — it annualizes to 150-200 small acquisitions a year. This quarter we didn't have any single transactions over $100 million; it was an amalgamation of smaller deals spanning roughly $0.5 million to $15-20 million. Trajectory-wise, I wouldn't read too much into one quarter. We feel very good about the pipeline and the ground game for the year.
You mentioned upcoming callable notes that present opportunities. The 2029 notes are callable at par soon and are the lowest cost debt, whereas the 2031 paper is more expensive and not callable at par for a few years. Guy, how do you think about that dynamic — taking out cheap debt at par versus paying a premium to take out expensive debt or accruing cash?
Bond math and return are simpler than asset acquisition returns. My job is straightforward: we evaluate each opportunity in the same framework. Taking out bonds at par versus taking out older higher-coupon bonds at first call is driven by return math; typically, given the high coupon on older bonds, even at first call it can be a better return to replace them. Given our overall liquidity and maturity profile, the exact maturities are less relevant. Under our capital allocation framework, most of the time replacing the older, high-coupon bonds wins out.
Okay. So it may be more likely that the 2031 would be the ones tackled.
Yes.
Your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.
You noted growth would be back-half weighted when gas takeaway improves. How do you see the production trajectory through the year if you keep the current activity pace, and where could you end up on an exit rate relative to full-year guidance?
If you grow further from Q2, that growth would by definition be back-half weighted. For longer-term growth measured in years, a normalization of Waha would support more meaningful growth. We're well protected today and getting stronger. Growth for us is always free-cash-flow focused: we grow when returns are higher and payouts are shorter; we maintain or reduce activity when returns are weaker and payouts are longer. Today we're excited about the barrels we're producing and accelerating in Q1 and Q2. There's still uncertainty on macro factors and the Iran conflict's resolution timing, so we maintain flexibility to pivot toward a meaningful growth program or back to maintenance on short notice.
On inflation: was there any inflation embedded in the $685 per foot number? Do you have views on whether inflation or diesel costs could pick up?
We started to see diesel prices pick up at the end of March, but there was very little inflation embedded in the $685 number. Outside of diesel, we have not seen meaningful inflation. Any pressure has mainly been direct diesel inflation or pass-through fuel surcharges from trucking providers.
Your next question comes from the line of Phillip Jungwirth with BMO.
You've spent a lot of time discussing improving gas realizations. There are several new NGL pipelines, LPG export terminals and G&P additions. Anything you can do on the NGL netback side to improve realizations versus Mont Belvieu, given you now produce over 100,000 barrels of NGLs?
We are constantly optimizing contractual NGL agreements to improve economics — typically pennies per gallon, not transformational changes. Our priority has been moving away from Waha because that had the largest impact on realized value. Regarding NGL takeaway and gathering and processing capacity, we feel good that midstream capacity is being built to service basin volumes, so NGL takeaway has not been a constraint. We continue to optimize all parts of the business.
How are you viewing Woodford prospectivity on the eastern side of your Lea County acreage and any plans to test it?
Woodford is similar to how we've approached Wolfcamp D and Avalon: where we hold Woodford depths, they are held while we watch development. Continental and others have drilled strong Woodford wells; it's exciting. There's more work to be done on gas takeaway and costs, so our approach has been to hold what we own and observe development. There may be a few tests, but Woodford won't be a big part of our program in the near term.
Your next question comes from the line of John Abbott with Wolfe Research.
You increased workover activity. How do you see LOE progressing over the course of the year with higher activity and higher diesel prices? What do you see as a normal go-forward LOE expense?
Most workovers are roughly split between capital and LOE. Anything that adds to reserves or requires an ESP is capital; others are LOE. Q1 had an abnormally low LOE partially due to a mild winter. Incremental workover activity will likely return LOE to our annual expectation. Our midpoint guidance for LOE was $5.45 per BOE, and we expect to average near that for the year. Workovers do come with extra barrels, so you get some benefit in the denominator as well.
On maintaining or adding activity: how do you think about price points for adding activity or reducing activity? If you add activity, do you hedge more? And if you see a pickup in the forward curve and concerns about service cost inflation, do you want to get ahead of that? How do you think about those variables?
We think about reinvestment primarily in terms of returns, not a specific oil price. An attractive payout window for drilling a well is roughly 12-18 months; that's an attractive return. If payouts are 18-24 months, we lean toward a maintenance posture. Our current midpoint guide shows about 6% year-over-year growth for 2026 versus 2025 — we view 2026 as a growth year and see attractive returns in the current environment. Growth beyond that will depend on macro outcomes and the duration of the current geopolitical developments.
Your next question comes from the line of Jeff Bellman with Daniel Energy Partners.
Looking at Permian takeaway, there are roughly 10-11 Bcf/d of new capacity over the next five years. How do you think about utilization of that capacity and implications for incremental oil production given the associated gas? Could the basin get gassier and might the industry target gasier zones in a few years?
Building takeaway is necessary and profitable; it's positive for the basin. We expect continued meaningful gas growth out of the Permian over the next five to ten-plus years, and the basin mix could become gassier over time as productivity and targeted zones change. For Permian Resources specifically, we are oil-weighted and do not expect to target gas zones in the next several years at current strip levels. While we have gas zones that are economic in a normalized environment, our high-return oil-weighted wells will generally receive capital preferentially.
The next question comes from the line of Paul Diamond with Citi.
On current natural gas curtailments, how should we think about the return of curtailed volumes? Is this mainly a second-half story as capacity comes online and Waha stabilizes, or could other factors bring production back sooner?
We have shut in high-GOR gas wells that don't make sense to produce in highly negative Waha environments. We plan to return those wells when it's economic, and we expect that timing to be in the second half. If negative Waha persists beyond that, we'll continue to make economically rational decisions and will not produce gas wells at a loss. Our goal is to maximize cash flow.
On M&A, given current volatility and reports of increased potential for larger packages to come to market, what scale opportunities have you seen?
Deal velocity is robust with many opportunities trying to fit into a summer/fall window. We expect more deals this year than in recent years. Our historical sweet spot has been scale deals in the several hundred million dollar range — those are the highest quality inventory deals that fit quickly into our portfolio. We are seeing more deals of scale this year and view that as positive. We'll remain disciplined on price and conviction.
The next question comes from the line of Leo Mariani with ROTH Capital.
You mentioned pulling TILs forward and have a goal around 250 TILs this year. If oil prices stay robust and returns are strong, what could that number move up to? Are we talking about 10 extra TILs, 20? Looking for an order of magnitude.
With the existing equipment and doing the efficiency improvements we're discussing, we could probably add roughly 5% incremental TILs for the year. That is achievable through compressing cycle times, drilling faster and completing faster. That level of acceleration is what we're executing in Q2 in real time. Back half of the year, depending on returns, we could add more activity or pull back toward the base plan, but for today, around a 5% incremental TIL increase is a reasonable estimate.
Regarding your $685 per foot, aside from speed and fewer bit trips, is there anything you see a year or two out that could be the next frontier to lower cost further?
We continuously optimize and implement improvements as we discover them. Recent examples include a new drilling approach that reduced drill-out time and higher water recycling, which materially lowered costs. Water recycling has been a focus because it saves on both CapEx and LOE. Looking out a couple of years, the next major step change may not be another cost reduction per foot but rather increased recovery per section or per well. Many companies have invested heavily to increase recovery, and a step change in productivity per acre could be a large source of value creation.
The next question comes from the line of John Annis with Texas Capital.
You noted the microgrids lowered electricity cost by about 30% at those sites. How scalable is that program across your asset base, and could it move the needle on corporate LOE over time?
On a site-by-site basis, microgrids materially move the needle. However, across the corporate footprint, most sites outside New Mexico use grid power, which is lower cost than microgrids. Within New Mexico, where generators are concentrated, installing microgrids has an upfront capex and reduces variable electricity costs and maintenance. We've eliminated eight generators to date and there are more opportunities, but at a corporate level it will likely affect LOE by pennies per BOE, not by dollars of magnitude.
On organic inventory expansion: do higher prices give you room to take more exploration risk, such as testing Avalon in northern New Mexico or further western steps out?
Our exploration approach hasn't changed dramatically with price. We tend to observe what others do and then take lower-risk steps out. We've been successful pushing Eddy County north and west in one-mile steps, studying geology and ensuring returns are comparable to prior wells. We also like Avalon and have tested areas further north after encouraging results by others. We will continue to test selectively, but expansion is generally incremental and risk-managed.
Inventory replacement is a long-term game for us and is evaluated over years, not quarters. Higher prices may help on the margins, but they don't change our long-term philosophy.
Your next question comes from the line of Gabe Daoud with Truist Securities.
You mentioned water recycling. How much water recycling is currently being done, and from a disposal standpoint, is pore space a concern given reports of disposal capacity getting full in parts of the basin?
Recycled water utilization was approximately 70% this quarter, which is a meaningful increase. We don't worry about disposal or pore-space constraints for our volumes because of our partnerships with well-capitalized midstream providers. Contractual arrangements typically place the disposal obligation with our midstream partners. If disposal needs increased, we are confident our midstream partners have the capacity to handle the water.
One quick follow-up: any inflationary pressures from service providers attempting to raise prices on equipment?
To date, the only inflation we've seen is fuel-related, mainly diesel increases and related pass-through surcharges. We haven't experienced broad inflation across service categories.
There are no further questions at this time. Mr. Walter, I would like to turn the call back over to you for closing remarks.
Thank you. As you can tell from this morning's results, the business is in a stronger position today than at any point in PR's history. We have an investment-grade balance sheet, a simplified corporate structure, the lowest cost in the Delaware Basin and a team that continues to set new records every quarter. Combined with a more constructive commodity environment, we believe we're exceptionally well positioned to continue compounding free cash flow per share and delivering outsized returns for our investors. Thanks to everyone for joining the call today and for following the Permian Resources story.
That concludes today's conference call. You may now disconnect.