Aug 6, 2026 earnings call — Record free cash flow and aggressive ground-game M&A
Permian Resources reported record free cash flow of $751 million in Q2 and updated full-year 2026 oil production guidance to 199,000 barrels per day.
Revenue $1.9B (est $1.7B) · EPS $0.93 (est $0.58)
Key quotes
"In total, year-to-date, we've acquired approximately 55,000 net acres in the core of the Delaware Basin for a total consideration of approximately $1.05 billion, executed through roughly 190 separate transactions."
"All of these characteristics support the goal we are all aligned on, increasing free cash flow per share over the long term to create shareholder value."
"The curtailments, combined with our firm transportation and hedging, allowed us to realize a natural gas price of $0.38 per Mcf for the quarter and an uplift of over $75 million of revenue on our natural gas sales."
Analyst Q&A 13
M&A strategy and pipeline
Q (Scott Hanold · RBC): Analyst asked about the M&A outlook and how their small bolt-on deals compare to larger marketed packages and lease sales. He also asked about Permian production, gas egress, and oil takeaway capacity.
A: They said their ground-game M&A is a long-term, consistent effort and they can keep executing it, but deal flow may vary quarter-to-quarter. They review publicly marketed packages but stay disciplined on purchase price to hit full-cycle returns. They feel good about oil takeaway capacity and expect midstream partners to add capacity; gas pipelines coming online handled recent volumes.
"I think for us, it's all about focusing on kind of full cycle and long-term value creation." — James Walter (CEO)
Eddy County expansion and growth plan
Q (Neal Dingmann · William Blair): Analyst asked if the Parkway bolt-on means greater confidence moving northwest into Eddy County and possibly further into Lea County. He also asked whether production growth is appropriate now or if they will keep building cash.
A: They said Parkway has been a strong area and there is white space both between and beyond existing positions; they are confident in the proven locations but will keep learning about upside zones. On growth, they won't forecast 2027 now and will decide based on returns: if oil prices and service costs make sense, they'll grow; if not, they'll run maintenance.
"Like Will has talked about in his prepared remarks, we're proud of team, how quickly we could respond, and how quickly we could bring those barrels." — James Walter (CEO)
Field productivity actions
Q (Neil Mehta · Goldman Sachs): Analyst wanted specifics on operational actions in the field to stay ahead on production and completions, and asked about lateral lengths and P&L impacts.
A: They highlighted water recycling as a key driver and said Q2 had the highest percent water recycled in company history. They are testing drilling changes like water-based mud in loss zones and slimmer hole designs to save costs. Lateral lengths have gradually increased and they expect modest annual increases, not sudden large jumps.
"I think it's the highest quarter we've had in PR history." — William Hickey (CEO)
Capital priorities and infrastructure
Q (John Freeman · Raymond James): Analyst asked how capital allocation priorities might change now that leverage is low, and whether expanding acreage requires new infrastructure spending.
A: They said growing the base dividend consistently is a priority and their capital allocation program will hold course. Most bolt-ons sit next to existing operations so no significant new infrastructure is needed beyond the current budget; Ward County bolt-on has about $25 million incremental CapEx.
"I think growing the base dividend consistently over time is a priority and always has been a priority." — James Walter (CEO)
Production, gas volumes, cash flow
Q (Kevin MacCurdy · Pickering Energy Partners): Analyst asked for a bridge from old to new production and CapEx guidance and the contribution from acquisitions and performance. He also asked if gas production is back online and the cash flow uplift from higher gas prices.
A: They said the Ward County bolt-on added 2,500 barrels a day at close, annualizing to 1,000 of the 6,500 barrel increase; most of the rest is higher working interest in 2026 projects and some accelerated workovers. All gas wells were brought back online at end of June and will make Q3 and Q4 more normal. They declined to forecast gas prices but noted current WAHA levels will contribute to back-half cash flow.
"And Kevin, on cash flow uplift, I think we're probably hesitant to forecast gas prices in the back half." — Guy Oliphint (CFO)
CapEx run-rate and maintenance
Q (John Abbott · Wolfe): Analyst asked whether the ~ $100 million CapEx increase in 2026 implies a similar step-up in 2027 if production is to remain flat, and how workover activity will trend.
A: They said most of the $100 million increase occurred in Q2 and that $1.95 billion spend this year is already annualized and drove roughly 10,000 barrels a day growth. They noted maintenance CapEx is lower than that range, and continuing at $1.95–$2.0 billion will grow production; workovers normalized after Q2 backlog was cleared.
"If you want to think about this year, we came into it, we were going to spend $1.85 billion and grow production minimal." — William Hickey (CEO)
Ward County trade and surfactants
Q (Phillip Jungwirth · BMO): Analyst asked for background on the Ward County bolt-on and acreage trades and whether similar non-op-to-op trades exist. He also asked about surfactant trials, the number of wells to deploy, results, and costs.
A: They said the Ward County deal was a creative multi-party trade that increased operated positions and they see more trade opportunities to net up working interest. On surfactants, they ran two trial pads this year and will stop there for now to study results; the program has averaged sub 1-year payouts even including wells with no uplift.
"On the average, that program has been very economic, kind of, call it, sub 1-year payouts on the aggregate, inclusive of the wells that we saw basically no uplift." — William Hickey (CEO)
Microgrids, compression, LOE
Q (Hsu-Lei Huang · TPH): Analyst asked about confidence in developing the new New Mexico acreage blocks, and about how wellbore design, power supply (microgrids) and compression optimization are flowing through financials and future upside.
A: They said they have already deployed 7 or 8 microgrids in New Mexico and that more microgrids and compression optimization remain, especially in New Mexico. These efforts, plus water recycling, helped hold or reduce LOE to near $5 per Boe and are ongoing ways to move costs down.
"I mean we've run at this point, 7 or 8 microgrids across New Mexico and areas where we historically have been on generator power." — William Hickey (CEO)
Royalty vs leasehold buys and development mix
Q (Joshua Silverstein · UBS): Analyst asked whether the recent buys included royalties and leasehold together, why royalty per-acre prices look low, and whether development plans shift between New Mexico and Texas.
A: They said their acquisitions this year are a mix but have been more weighted to higher NRI leasehold because standalone minerals and royalties can be expensive and fail their return thresholds. They expect development to remain roughly 70% in New Mexico and the rest in Texas.
"I'd say for us, it's tended to be more weighted towards kind of higher NRI leasehold." — James Walter (CEO)
Future land spend and productivity
Q (Gabe Daoud · Truist): Analyst asked if they can frame expected additional land spend after ~$1 billion YTD, and whether productivity will stay flat given new assets and initiatives like surfactants.
A: They said they can't predict future land spend and will keep hunting for attractive deals. On productivity, they listed many trials (surfactants, proppant, cluster spacing) and said they expect '26–'27 productivity to be similar to '24–'25, drilling the same benches the same way.
"We are still kind of marching across our position in both New Mexico and Texas drilling the same benches in the same way and expect the same productivity as we've seen in the past." — William Hickey (CEO)
Costs per foot and deal pipeline
Q (Leo Mariani · ROTH): Analyst asked if well cost per foot will rise in H2 with inflation, whether $675 per foot target is still reachable, and if the deal pipeline remains robust.
A: They said inflation (steel, fuel) made $675 a longer shot but they've offset much with efficiencies and remain near prior targets; if oil falls and fuel normalizes, $675 is attainable. They also said deal activity is strong and they expect to exceed the prior two-year pace.
"I think it's probably safe to say we will exceed the last 2 years average this year." — James Walter (CEO)
Emerging benches and gas handling
Q (Paul Diamond · Citi): Analyst asked how emerging benches (Avalon, deeper Wolfcamp, Woodford, etc.) are developing on their footprint and whether nat gas handling and hedging plans are settled.
A: They said Avalon and deeper Wolfcamps are moving north quickly and have been very productive; other benches like Woodford are watched but not core to the '27 plan. On gas, they feel good about the deals they made, believe capacity into '27 covers roughly all net volume, and will be opportunistic on hedges.
"And I think the capacity we have going into '27 covers roughly all of our net volume." — Guy Oliphint (CFO)
Water-based mud vs oil-based mud
Q (Sean Mitchell · Daniel Energy Partners): Analyst asked whether water-based mud affects drill time versus oil-based mud and if there are time savings.
A: They said water-based mud does not save drill time; it is used where they take losses to save cost. The slim-hole design gives the main drill time savings, roughly a day per well.
"No. I don't think water-based will be a time savings versus oil based." — William Hickey (CEO)