管理層發言
Good morning, and welcome to Permian Resources conference call to discuss its second quarter 2026 earnings. Today's call is being recorded. A replay of the call will be available by visiting the company's website at www.permianres.com. At this time, I will now turn the call over to Hays Mabry, Permian Resources Vice President of Investor Relations, for some opening remarks. Please go ahead.
Thanks, Eldi, 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. Q2 is a standout quarter for Permian Resources. We delivered record free cash flow of $751 million, an increase of almost 50% quarter-over-quarter and record free cash flow per share of $0.88. These results reflect our team's ability to respond quickly and decisively to a volatile commodity environment. Our activities this quarter are a reminder of the uniqueness of PR's business model. We can respond quickly to market conditions. We have a differentiated approach to sourcing and executing acquisitions, and we are relentlessly improving the capital efficiency of our business on a go-forward basis. 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. Turning to the quarter. Oil production came in at approximately 198,000 barrels per day, up 3% quarter-over-quarter. Slide 4 shows the key drivers that drove that oil production growth. When oil prices moved higher, our team in the field responded immediately. We increased the number of workover rigs by 50%, which improved run times and quickly accelerated incremental barrels. At the same time, our successful ground game drove working interest in completed wells to approximately 82% for the quarter, up materially from our original expectations of 75%. Combined with strong well performance, these actions generated 6,000 barrels per day of oil growth quarter-over-quarter for cash capital expenditures of $521 million. One thing I'd highlight is our continued success in increasing working interest ahead of development. This has always been part of the PR playbook, but our BD and land team have executed at an exceptionally high level this year. We view these acquisitions as some of the highest rate of return deals that we do, given that their near-term impact as evidenced from our higher working interest not only in Q2, but also for the remainder of the year. Incremental workovers and ground game transactions are exactly the types of investments we want to make in a volatile market. Both generate incremental oil production and cash flow almost immediately, allowing us to recycle capital quickly and derisk returns through shorter payback periods. Turning to natural gas. Our team demonstrated their relentless focus on maximizing free cash flow as they navigated a severely depressed WAHA market during the quarter. As many of you are aware, WAHA natural gas prices averaged negative $3.14 per Mcf during Q2 and traded as low as negative $9.52 per Mcf. So rather than selling natural gas at negative prices, we proactively curtailed production on high-GOR wells with WAHA exposure, reducing natural gas production by approximately 20% quarter-over-quarter. 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. When WAHA pricing improved in late June, we returned all previously curtailed wells to production without any operational issues. I want to give a big shout out to the field team for putting in the hard work to make this possible during the quarter. On the D&C side, we offset inflationary pressures from rising diesel prices with continued operational efficiency gains through longer laterals, increased water recycling, deployment of water-based mud and new wellbore designs. We've also begun surfactant trials on completion and production operations. We're still early in evaluating surfactants, but we're encouraged by the initial results. Between continued operational efficiency gains and the potential to improve recoveries, there are a lot of ways for us to continue our path of increasing capital efficiency. As you can see from today's results, the quality of our assets, combined with our basin-leading cost structure, has driven a step change improvement to our business over the last several years. As a result, we achieved record free cash flow in Q2 of $751 million. This is more than we generated in all of 2023, and we expect full year 2026 free cash flow to be nearly double what we generated in 2024. And with that, I'll turn it over to James.
Thanks, Will. Before we start talking about what's been a great start to our 2026 BD effort, we want to discuss how Permian Resources approaches acquisitions and how that fits with our value creation story. When we founded Colgate in 2015, we moved to Midland with exactly 0 acres, 0 production and Will and I were sharing a single 200-square-foot office. Our goal at the beginning was to buy high-quality assets, operate them efficiently and underwrite them conservatively so that our invested capital would generate real cash-on-cash unlevered equity returns. And from those humble beginnings, we grew Colgate from an idea to the business it is today with over 500,000 net acres and over 200,000 barrels of oil per day. But our focus was never to build a large-scale business as Permian Resources now, but rather to maximize the return of every dollar we invested in the business. So how do we get here? Because we've honored the same strategy and philosophy in how we underwrite and how we operate, we're working relentlessly to find deals that meet our very high underwriting standards and targeted full cycle returns. And we use that time and time again, small deals add up, you create value for shareholders, and the business naturally gets bigger. With that, I'm excited to talk about what we've done in 2026 to date. Starting with the largest deal on Slide 8, we closed on an acquisition of approximately 2,000 net acres and 5,000 Boe a day in Ward County for $520 million. This acreage directly offsets our existing asset base is 100% held by production, and provides an extended runway of high-return inventory. Shortly after we closed on the Ward County asset in July, we signed a trade agreement with an offset operator, utilizing a combination of the recently acquired bolt-on acreage, the legacy PR acreage and some other acreage that we have. This acreage helps address some of the challenges with the stand-alone Ward County acquisition, namely, being majority non-operated, low working interest and somewhat scattered. The trade also increases the number of operating net locations from 50 to 120, while increasing the average lateral length by 20%. We view this trade as a true win-win for PR and our counterparty, who is a valued industry partner, as it helps them to further core up their acreage position and increase their working interest in their own operated units. We expect the trade to close during Q3. Finally, the Parkway bolt-on project in Eddy County is a great example of how our proprietary data and Midland relationships create opportunities others simply do not see. Following the success of a delineation well we drilled in late 2025, we quietly assembled a contiguous position of approximately 15,000 net acres with 2-mile lateral lengths and an 82.5% 8/8ths NRI. Our partner in this deal, Tascosa Energy Partners actually brought this deal to us over drinks in Midland. We've been fortunate to know this team for a long time and bought a big deal from them a couple of years back. But I think more importantly, this deal is a scaled example of the Midland-born deals that we do with our friends and partners on a regular basis, and that we think provides a real competitive advantage to Permian Resources. 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. These acquisitions added approximately 330 high confidence, high NRI locations that immediately compete for capital in our portfolio. Ultimately, we think the valuation metrics for the deals we have done so far this year speak to the strength of our approach: $13,000 per net acre, $8,000 per net royalty acre and $2.5 million per net location. Slide 11 summarizes why we believe our acquisition strategy is truly differentiated. Our focus is on buying high-quality assets, pursuing accretive transactions where PR has a commercial technical or operational advantage. We continuously hunt for off-market deals and look for areas where we have distinct advantages or can create an edge that allows PR to underwrite higher full cycle returns. The edge can come from our leading cost structure, proprietary service information or simply access to a deal that isn't widely marketed. While this is not easy and requires a ton of work, we pride ourselves on being creative and not afraid to lean into harder, less obvious deals. We are confident we'll be able to continue this successful track record for years to come. Our financial discipline allows us to execute meaningful transactions like we have announced today, while retaining a fortress balance sheet, with Q2 leverage of approximately 0.5x and expected year-end leverage of approximately 0.5x. All of this leads us to our updated and improved plan for 2026. As Will mentioned in his prepared remarks, the success of our ground game has allowed us to significantly increase our working interest for full year 2026. This will allow us to meaningfully grow production while maintaining the same completion crews, rig count and operating efficiencies we have achieved this year. Our updated production guidance of 199,000 barrels of oil a day for the full year 2026 is 10% higher than 2025, while our CapEx midpoint of $1.95 billion is approximately 1% lower than the capital we spent last year. This all highlights the strides that our team is making to continue to improve the capital efficiency of our business and to grow free cash flow per share every year. Concluding with Slide 14, our focus on full cycle returns has allowed the company to generate outsized value creation for our investors. $1 invested in Colgate in 2015 would be worth nearly $50 today, representing a greater than 50% compounded annual return. And we've continued that same philosophy and performance at scale with Permian Resources, nearly tripling our total shareholder returns since formation in 2022. Most importantly, our business model has not changed. We are confident in the combination of our high-quality asset base, peer-leading cost structure and differentiated approach to acquisitions will continue our track record of long-term value creation. We live in an industry that in some ways has been defined by consolidation and scale, but we'd like to be defined by prudent investment of capital, free cash flow per share growth and ultimately leading total shareholder returns for our investors. Thank you for tuning in today, and now we'll turn it back to the operator for Q&A.
分析師問答
The conference call is now open for questions. Your first question comes from the line of Scott Hanold with RBC Capital Markets.
Obviously, the ground game M&A has been a staple of you all for the last number of years. And it looks like you had a pretty successful run here in the last couple of months. Can you give us a sense of what you see moving forward on the M&A landscape? And also how do you kind of compare and contrast the activity you've been doing versus looking at some of the larger packages that are a little bit more, I guess, competitive like the federal lease sale or marketed deals?
Yes. Thanks, Scott. I think on the ground game side, that's an effort that's been building and consistent for the whole 11 years we've been running this business. We've got pretty much the same team, the same people operating at an extremely high level. That may ebb and flow a little bit from quarter to quarter, but over years, we are really confident we can continue to execute and grow that part of our business. I think the opportunity set in front of us looks as good as it ever has, and we're excited and confident that we can continue that, but it may not be the same every single quarter. In terms of larger packages, we've always looked at everything in the Delaware. You should assume we are in the mix and evaluating any package of quality that is out there on the publicly marketed side. Some of these federal or state lease sale assets are good assets and there has been some really good stuff that transacted this year, but our focus on full cycle returns and generating outsized equity returns for investors has us being really disciplined on purchase price. Are some of those assets that transacted assets we'd like to own? Absolutely. But were we able to get to those purchase prices and still achieve our targeted returns? The answer is no. So for us, it's all about focusing on full cycle and long-term value creation. If bigger packages meet those return thresholds and standards, then we'll be excited to do them and we'll continue to be patient.
Got it. And my follow-up question is more kind of Permian macro related. Certainly, with new egress coming on for pipelines, you're seeing probably a next surge of gas coming, including your production was offline. How do you see activity pace from a lot of offset operators, any kind of non-operated activity with improved egress? And do you expect a surge of production? And I'm just kind of curious on oil takeaway capacity, if you think that becomes a constraint in the next couple of years or so.
I'd say hitting the last part first, we feel really good about oil takeaway capacity for the next few years. We're hopeful we've learned a good lesson on the gas situation over the past 12 months that you have to get ahead years in advance. We're fortunate on the oil side; there's a lot of capacity today and we expect that to be the case. We continue to grow for years to come in the Permian, which is not guaranteed but certainly possible. We're confident our midstream partners will be working with people like us to get further ahead of that. On the gas side, we haven't seen any meaningful reaction from an activity level. It seems like the pipelines that are coming online this quarter were able to handle the new gas that was brought back online, and any incremental growth today. We are hopeful that we're entering a new era in WAHA gas where you get past this period of dislocations, and pipeline capacity will be able to keep up with Permian growth. There's a new eagerness and desire to build pipelines coming out of the basin, and people do believe this basin is going to grow its gas volumes for a long time. There are also exciting downstream demand opportunities. So we feel a lot better about both crude and gas than we have in the last few months.
Your next question is from the line of Neal Dingmann with William Blair.
James, maybe staying on the same vein, my first question just around M&A specifically. Is it fair to say that the Parkway bolt-on suggests you all continue to have more confidence as you move northwest to Eddy County? And just wondering either there or further into Lea, would you all continue consider moving further north in New Mexico overall?
Yes. The Eddy County Parkway bolt-on area has been a tremendous asset for Permian Resources since we bought our first deal there back in summer of 2016. We've seen it continue to work as you push modestly west and modestly north. We've been surprised by how strong the well performance is in the area referenced today. We see a lot of white space, not only moving north and west but also in between our existing positions. Most of the bolt-on activity now is more in between our existing holdings. We still see a lot to do in the Parkway area of Eddy County and are excited about the well results we've seen and the upside potential.
Perfect. And then my follow-up just on capital allocation, maybe for you or Guy or Will. Specifically, we've seen a couple of your peers boost activity in the last few months. Do you all believe production growth in this environment is appropriate given the commodity backdrop and if not, is the plan just to keep building cash?
We don't forecast next year today. For 2026, given oil prices at the beginning of the year, we believed it made sense to invest more capital and grow production more than the flat expectations we had coming into the year. We were strong believers that this environment warranted that. As Will discussed, our team responded quickly and brought those barrels. Growth from here or next year will depend on the returns environment. We've always talked about growth in a returns-driven framework: if oil prices are high and service costs are low, you'll probably see us grow. If oil prices are lower and service costs higher, you'll see maintenance mode. It's going to depend on how the macro settles out. Today it's too early to tell, but we'll keep watching and we've proven we can react quickly when the time comes.
Your next question is from Neil Mehta with Goldman Sachs.
Yes. Continued operational momentum as we think about your production. James, can you talk a little bit about some of the things that you're deploying out in the field to stay ahead of expectations operationally?
I mentioned a few in the prepared remarks. One that I emphasize every quarter is water recycling. We had another tick up on percent water recycled in Q2 — the highest quarter we've had in PR history. We're continuing to make progress on incremental water recycling. We have a strong relationship with a large water company in New Mexico, and as they build out an integrated system, we are a big beneficiary. On drilling, which I referenced in Q1 as the next level of step-up, we started to introduce water-based mud in areas where we typically take losses; with oil at high prices, the payback on using water-based mud can be meaningful, roughly $5 to $7 a foot of savings on those wells. We also transitioned to a slimmer hole design in New Mexico: same long string, still run 5.5-inch all the way back to surface, but running it inside 8 5/8s instead of 9 5/8s. That saves steel, especially as casing prices are projected to rise in the back half of the year, and saves time — smaller holes drilled faster and savings in cement. We are willing to accept increased diesel prices with increased oil revenue, but we have offset those inflationary pressures with the efficiency gains I described.
That's helpful. And then your perspective on lateral lengths — with bolt-ons you'll extend laterals given block up acreage more. How long can you get these laterals, and what does that mean for P&L?
Lateral length is the most effective way to reduce D&C per foot. We've ticked up every year for the last two to three years, moving from just under two miles to now right at 11,000 feet. We drilled our first four-mile lateral in Q2, which was a big success. The combination of our willingness to drill longer, our ability to drill U-turns when needed, and the blockiness of our position means lateral lengths will continue to tick up over time. I don't expect a step change from 11,000 to 15,000 year-over-year, but an increase of around 500 feet, plus or minus, each year is a reasonable expectation going forward.
Your next question is from John Freeman with Raymond James.
In the slide deck, you show the capital allocation strategy and in the first half the spend has been skewed to accretive acquisitions along with debt repayment. You've got leverage now at the bottom end of your target range. Going forward, any change in how you think about cash priorities across acquisitions, balance sheet, buybacks, maybe even growing the dividend?
Growing the base dividend consistently over time is a priority and always has been. Beyond that, we don't have plans to change our capital allocation program. It's working well. The business is generating a lot of cash. We've paid down considerable debt over the past two years, done acquisition activity, and delevered the business to roughly 0.5x. For the foreseeable future, you'll see us hold the course.
Okay. On the back of all the accretive acquisitions, most have increased working interest in fields where you're already present, but some extend your footprint. Does that necessitate infrastructure investments we should be thinking about in upcoming years?
No, nothing outside of what's already baked into our plan and budget for the year. These areas are still right next to existing PR offset operations, we have the right partners on the midstream side, and most of the activity is one to two miles from existing PR operations. The only exception would be the Ward County bolt-on, which will have a minimal incremental CapEx associated with taking over a new asset.
I think the only exception is Ward County, where there will be a minimal, roughly $25 million incremental CapEx associated with taking over a new asset.
Your next question is from the line of Kevin MacCurdy with Pickering Energy Partners.
Can you bridge the old production guidance to the new production guidance and do the same on CapEx, maybe breaking out the contribution from the higher working interest, the production you bought and any pull forward or outperformance?
Kevin, it's Guy. On the production side, we were at 192,500 barrels a day at Q1, and our guidance after Q1 is 199,000 today. The only production we acquired with this approximately $1 billion of acquisitions was 2,500 barrels a day of production at the time we closed the Ward County bolt-on a week ago. When annualized, that's 1,000 barrels of the 6,500 barrels a day increase. The significant majority of the remainder is just higher working interest in our 2026 projects, with a little contribution from accelerated workovers. On the capital side, we're up $100 million; $25 million of that is takeover costs associated with the Ward County bolt-on, such as putting in equipment that meets our standards. The remainder is due to higher working interest in the 2026 TILs. We increased our guidance for working interest in 2026 TILs from 75% to over 80%. When you put that together, it's capital efficient and explains the increase in capital relative to the production increase.
Appreciate that detail, Guy. My follow-up: is your gas production back online now that WAHA prices are better? And can you give any sense of cash flow uplift you're seeing for the back half of the year just from better gas prices?
All the wells are back online. We brought them online at the very end of June when WAHA rebounded, and we've had all the wells online since. Q3 and Q4 will be much more normal with respect to gas.
Kevin, on cash flow uplift, we're hesitant to forecast gas prices. But we produce over 750 million cubic feet a day net. Given where WAHA is today, and with $1.50 to $2 in some regional hubs and other hubs, it will contribute in the back half of 2026. That's why we commented on 2027 as we think about growing free cash flow over time. We've done that despite realizing almost nothing from our dry gas stream, and both the curves and our transportation into 2027 set us up for a much better year-over-year result.
Great. I appreciate that.
Your next question is from the line of John Abbott with Wolfe Research.
Question on CapEx. For 2026, from the increased working interest and carryover from Ward, you've increased full year guidance by about $100 million on the midpoint. If you annualize that, is $200 million a reasonable step-up as one thinks about 2027 if you were to maintain flat production, or are there other factors to consider?
I want to clarify: the majority of that $100 million increase happened in Q2, and I don't think you can double it to annualize it. That $100 million is the annualized increase. We came into the year planning to spend $1.85 billion and grow production minimally; now we're at $1.95 billion and expect to grow production by 10,000 barrels a day. That $100 million is annualized. Going forward, if we spend in the $1.95 billion to $2 billion range, we will continue to grow production. Maintenance is below that range, and any decision in 2027 between growth or maintenance will be subject to market conditions.
That $1.95 billion grows production about 10%, which is a substantial growth rate. It's highly capital efficient: 17,000 barrels per day year-over-year growth and 10% is a strong capital efficiency story.
Extremely helpful. Then the step-up in workover activity in Q2 — how does that trend for the remainder of the year?
It will normalize. The step-up in Q2 basically chewed through our entire backlog of workovers. So we are back to normal course, fixing wells as they come offline, with a rig cadence more like what we had in Q1.
Your next question is from Phillip Jungwirth with BMO Capital Markets.
Can you provide background on what you did in Ward County with the bolt-on and subsequent acreage swap? It looks like acreage trades between two or more parties gave you a larger operated position. Are there similar opportunities where legacy checkerboard acreage positions exist, and how much of a discount do you typically see for non-op acreage?
That was a really cool deal. Many things came together: our team, great collaboration with multiple counterparties on the trades, and yes, we love opportunities that are win-win and make our position better. This year has been active on the trade front. We've found more opportunities to net up our working interest and trade out of non-op into operated positions, like you see here. We may not see another deal as large in the back half of the year, but we've done some big ones to start the year and are always working on that.
Okay. And can you talk about productivity initiatives such as surfactants and completion design changes? How many wells are you looking to deploy surfactants on this year? You mentioned you're encouraged by early results and any color on incremental costs?
On the completion side, we pumped two surfactant trials on two different pads with control and test wells. One of those is online; the other has been fraced but is not yet online. That's probably where we'll stop for this year. We'll analyze 60-, 90-, and 180-day data and by next year have a better feel for program size. On the production side, there are two or three pads across both basins where we've pumped surfactant in late life, typically around an ESP failure, and have seen uplifts up to north of 100 barrels a day and some de minimis results. On average, that program has been very economic — roughly sub one-year payouts on aggregate, inclusive of wells with no uplift. We're encouraged that even with dispersion of results, the program is economic on average. The team is working to increase the frequency of the high-uplift responses and reduce the low or no-uplift outcomes before rolling it out at scale.
Your next question is from Oliver Huang with TPH Research.
Looking at what you picked up on the New Mexico side — this is relatively virgin rock. You referenced the Tascosa well in the Northwest Parkway area being a step out. Are you 100% confident to carry out your development program there, or will you need more baseline work to feel comfortable with the entire block?
We are really comfortable in the primary zones. The deals and locations we underwrote are high-confidence. As you get to some upside zones, whether two or three productive zones or four or five is still to be determined. We'll continue to learn about the Parkway area and the Tascosa acquisition over time, but we have a high degree of confidence in the proven locations that went into the 330 underwritten locations. Over time we expect some upside locations to be proven up and come into the plan.
Okay. And maybe on the operations side, could you provide more detail on wellbore design improvements and optimization of the power and compression fleet? How much of that is already flowing through the financials today, and how much more runway do you see?
A decent amount of these initiatives is flowing through the financials today. We've installed seven or eight microgrids across New Mexico in areas historically on generator power. There's more to do, but it's New Mexico-centric because Texas Delaware has line power. On compression, optimizing fleet performance improves run times; microgrids improve ESP run times versus one-off generators. All of this contributes to holding LOE flat or reducing it over time, which is not normal in the industry. We've historically been around $5.50 per Boe LOE; in Q1 and Q2, even with significant gas curtailment, we're pushing closer to $5 per Boe. Water recycling is a big needle mover since water disposal is our largest LOE cost; the more we recycle, the more we save on LOE. Doing these initiatives together is where you really move the needle.
Your next question is from Josh Silverstein with UBS.
Can you give more detail on royalty acquisitions versus leasehold acquisitions? Were these done in separate transactions or together with both leasehold and royalty? And typically royalty value is higher — you appear to be paying lower prices for royalty acreage versus leasehold. Any detail?
Historically and in the first half of this year, we've acquired a mix of straight minerals and royalties versus high NRI leasehold. It's tended to be more weighted toward higher NRI leasehold. Minerals and royalties on a stand-alone basis can get expensive, and we haven't always been able to buy much at our return thresholds. Going forward, expect more royalty acquisitions to come paired with leasehold because we can apply the full suite of PR competitive advantages to combined interests. The lower dollar per net royalty acre values you're seeing are the result of acquiring deals at attractive prices using creative structures. Those creative approaches allow us to buy leasehold and royalty interests at what we view as attractive prices.
Thanks. Along those lines, any shift in development plans given the leasehold and royalty acreage acquired? More capital towards Texas assets or still favor New Mexico? I assume you want to keep working interest high.
The development split will be consistent with recent years: roughly 70% or a bit north to New Mexico and the rest in Texas. That aligns with where we've been the last two to three years.
Your next question is from Gabe Daoud with Truist.
Hard to nail down opportunities, but can you frame what spend on land might be for the rest of the year? You've done about $1 billion year-to-date; any framework for additional spend?
We don't provide guidance on future land spend. We're always looking and hunting for high-quality assets at prices that generate attractive full cycle returns. We've got good momentum and the ground game continues to work. In terms of predicting the next 12 months exactly, that's difficult.
Understood. Quick follow-up: you talked about surfactants and productivity. Can you quantify or discuss other productivity initiatives, and should we expect flat productivity year-over-year, particularly with new assets?
There's a long list of initiatives. Six months ago it was lightweight proppant; now surfactants are prominent; in between we've tested cluster spacing and completion tweaks. We're testing and studying everything and will be better able to identify big winners once data matures. For well productivity, we don't expect step changes in recoveries; productivity will be driven by the duration and depth of the inventory. Expect 2026 and 2027 productivity to be similar to 2024 and 2025 as we continue to drill the same benches similarly in both New Mexico and Texas.
Your next question is from Leo Mariani with ROTH.
Can you provide more detail on where cost per foot may be headed? In 2Q you said well cost per foot was pretty flat versus 1Q. Do you expect those to go up with inflation in the second half, or can efficiencies counteract that? You had a $675 per foot target at one point — are you there or is that later?
The run-up in crude and associated demand on steel has pressured our target, but we've offset much of that with efficiency wins on drilling, water recycling, and sand. Those wins help counter inflation. We're slightly north of 80% working interest in the back half and still keeping CapEx sub $2 billion, which shows progress. Achieving $675 per foot feels like a longer putt than when we entered the year, but we're still on target relative to where we began. Diesel and casing costs are key variables; if oil prices dip and fuel resets to prior levels, $675 is attainable. If oil runs, it's less likely, but revenue offsets that.
Makes sense. How robust is the deal pipeline compared to previous months? Are you getting a lot of looks?
Yes. We've spent about $1 billion over the last two years combined and already matched that pace partway through 2026. It's safe to say we will exceed the last two-year average this year. The ground game consistently produces opportunities month in and month out. Bigger packages are lumpier, but there are still interesting deals. We continue to be disciplined, do the right deals at the right prices, and pass on ones that don't make sense. We're confident the approach will continue to work.
Your next question is from Paul Diamond with Citi.
Discussion of emerging benches across the Midland and Delaware — how do you see that developing on your footprint? Any update from the last time we spoke?
I mentioned earlier the success of Avalon and deeper Wolfcamps moving north in Lea County. Since the prior call, full development and stacking Avalon has been some of the most productive wells we've drilled. We're seeing the deeper Wolfcamp move in Eddy County as well. As for benches like Woodford or Brushy, we own them on some assets and not others. We're keeping an eye on them, but they are not a core part of our development plan for 2027. We'll watch for serendipity, but they are not a large near-term focus.
Understood. Over the last year you've adjusted how you realize natural gas. Are you happy with the current level of transportation and hedging going forward, or should we expect more changes?
Paul, we feel great about the deals we've done to address gas takeaway. We identified this as an issue a couple years ago and have interim agreements with partners that served us well. The capacity we have going into 2027 covers roughly all of our net volume. We'll continue to optimize the portfolio and handle growth in gas volumes as we grow oil production and acquisitions. On hedging, we'll be opportunistic as we always have been. We spend time thinking about appropriate basis and where to sell gas, but I view that more as optimization than a must-do.
Your next question is from Sean Mitchell with Daniel Energy Partners.
Will, you talked about offsetting rising costs by using water-based mud versus oil-based mud. Are you seeing differences in drill time with water-based versus oil-based?
No. Water-based mud does not typically save drill time versus oil-based. The benefit is cost savings in areas where you would otherwise take losses. Our drill time wins are coming from the slim-hole design; moving to 8 5/8s intermediate instead of 9 5/8s allows a smaller hole, faster drilling, and we've saved almost a day per well on average.
Your last question is from the line of John Annis with Texas Capital.
John, do you have your mute on? We can't hear you. Okay. Operator, I think we can hand it back.
We can close the question-and-answer session. There are no further questions at this time. I will now turn the call back to James Walter for closing remarks. Please go ahead.
Thank you. As you can tell from this morning's results, the business is performing at the highest level in PR's history. We delivered record free cash flow this quarter, responded quickly and decisively to a volatile commodity environment and added high-quality inventory at attractive valuations — all while maintaining an investment-grade balance sheet and the lowest cost structure in the Delaware Basin. We believe we are exceptionally well positioned to continue compounding free cash flow per share and delivering outsized returns for investors going forward. Thanks to everyone who joined the call today and for following the Permian Resources story.
This concludes today's call. Thank you for attending, and you may now disconnect.