Q2 2025 Earnings Call Transcript

Welcome to Devon Energy's Second Quarter 2025 Conference Call. [Operator Instructions] This call is being recorded. I'd now like to turn the call over to Mrs. Rosy Zuklic, Vice President of Investor Relations. You may begin.

Good morning, and thank you for joining us on the call today. Last night, we issued Devon's second quarter earnings release and presentation materials. Throughout the call today, we will make references to these materials to support prepared remarks. The release and slides can be found in the Investors section of the Devon website.

Joining me on the call today are Clay Gaspar, President and Chief Executive Officer; Jeff Ritenour, Chief Financial Officer; John Raines, SVP, Asset Management; Tom Hellman, SVP E&P Operations; and Trey Lowe, SVP Technology and Chief Technology Officer. As a reminder, this conference call will include forward- looking statements as defined under U.S. securities laws. These statements involve risks and uncertainties that may cause actual results to differ materially from our forecast. Please refer to the cautionary language and risk factors provided in our SEC filings and earnings materials.

With that, I'll turn the call over to Clay.

Thank you, Rosy. Good morning, everyone. Thank you for joining us today. Devon delivered another quarter of production outperformance, capital reduction and improved 2025 outlook, driven by our unwavering commitment to operational excellence and financial discipline.

Our strategic priorities on Slide 3 remain steadfast. Operational excellence, advantaged asset portfolio, maintaining financial strength, delivering value to shareholders and cultivating a culture to succeed. Amid market volatility, our veteran leadership team is not distracted by the headline or tweet du jour. We keep our eyes focused on the larger macro signals, and we have guided our team's energy towards controlling the controllables.

As you will hear, during the quarter, we avoided the distractions and have made significant progress towards our business optimization goals of making Devon a more efficient value creation machine. Our optimization plan will create an incremental $1 billion of annual free cash flow by the end of next year. While cost cutting is part of the strategy, our focus is on driving value to the bottom line. Many of the wins are tied to production enhancements, inciting a culture of continuous improvement and a heavy dose of technology.

Only 4 months into this initiative, our team has already captured 40% of our target. As I sit here today, I'm highly confident in our ability to achieve our $1 billion target on time and as a result, create significant and sustainable value for our shareholders. Consistent with our strategy to enhance our asset portfolio, we completed the sale of the Matterhorn Pipeline in Q2. Then on August 1, we acquired the remaining noncontrolling interest in Cotton Draw Midstream. These transactions are value- enhancing and strengthen our financial position to support future growth.

By optimizing our midstream holding, these deals bolster our E&P operations and give us long-term value creation for our shareholders. Let's turn to Slide 4 and discuss our quarterly highlights. The second quarter demonstrated the strength of our capital program and diversified portfolio. As I mentioned, our second quarter production exceeded the top end of our guidance.

These results were driven by our franchise asset, the Delaware Basin and strong performance across our other assets. Continued efficiency gains and effective supply chain management allowed us to outperform expectations with capital spending coming in 7% below guidance. The impressive performance on both capital and production generated significant Q2 free cash flow of $589 million and further strengthened our financial foundation. Approximately 70% of the free cash flow was returned to shareholders via dividends and share repurchases, underscoring our reinvestment strategy and commitment to delivering meaningful long-term shareholder returns.

Let's take a closer look at some of our operational metrics. Slide 5 showcases the significant operational efficiencies we are achieving across our portfolio. In the Delaware, our teams have continued to push the envelope in both drilling and completions. By leveraging our existing -- or excuse me, our extensive data streams and our proprietary in-frac and indrill AI agents, we're able to capture operational enhancements in real time and drive efficiency in our critical operations.

In parallel to this real-time operational assistance, we're also leveraging design improvements, simul-frac implementation and relentless focus on safety and execution. These enhancements have resulted in another 12% year-over-year improvement in drilling costs and a 15% improvement in completion costs. These are not just onetime gains. They reflect the ongoing commitment of our teams to drive meaningful long-term improvements in how we operate.

We are seeing similar momentum in the Williston, where our innovative approach has delivered $1 million in savings per well since the Grayson Mill acquisition last year. We've reduced total well costs through design enhancements, improved drilling and completion practices and by leveraging technology. Finally, in the Eagle Ford, I'm pleased to report that we've fully captured the $2.7 million in savings per well that we set out to achieve as part of the dissolution of the JV in April. Overall, the operational highlights demonstrate how our teams are continuously seeking new ways to drive efficiency and deliver value.

Let's turn to Slide 6. You can see how these operational improvements are driving real capital efficiency gains. Since November, we've reduced our 2025 capital guidance by 10% or $400 million. We've achieved these capital reductions while regularly increasing our next quarter production guide and maintaining a strong 2026 production outlook. This outcome is a direct result of disciplined capital allocation, ongoing operational improvements and importantly, our commitment to leveraging technology across the business.

Our proprietary AI tools, agents and models are embedded throughout our operations from drilling and completions to real-time production optimization. These technologies enable us to quickly source and analyze vast amounts of data, make informed decisions faster and continuously refine our workflows. As I mentioned before, we're not just cutting costs. We are optimizing well performance, reducing cycle times and streamlining field operations, all while delivering production performance and strengthening our financial position.

These are sustainable structural gains that will translate into more efficient capital deployment, stronger free cash flow and long-term value. With that, I'll hand the call over to Jeff.

Thanks, Clay. Turning to Slide 7, where we highlight another quarter of strong financial performance for Devon. In the second quarter, we delivered core earnings of $0.84 per share, EBITDAX of $1.8 billion and operating cash flow of $1.5 billion. After funding our capital requirements, we generated $589 million in free cash flow.

This was driven by production exceeding the top end of our guidance, reflecting the excellent operating performance highlighted by Clay, disciplined capital investment resulting in a 7% outperformance versus expectations and production cost improving 5% from the prior period due to reduced downtime, lower workover expenses and lower production taxes. In addition to strong organic free cash flow, we closed the $372 million divestiture of our equity interest in the Matterhorn pipeline, resulting in $307 million pretax gain. With the associated taxes from this divestiture, our current tax rate was approximately 21% for the quarter, above our recent run rate.

With this robust cash generation, we delivered significant value to shareholders, paying $156 million in dividends and allocating $249 million to share repurchases. We remain firmly committed to our capital allocation framework, balancing high-return investments with substantial cash returns to shareholders. Moving to Slide 8. Our financial strength and liquidity position remain a clear differentiator for Devon. We exited the quarter with $4.8 billion in total liquidity, including $1.8 billion in cash on hand.

Our net debt-to-EBITDAX ratio improved to 0.9x, reflecting our ongoing focus on maintaining a strong balance sheet. Our $2.5 billion debt reduction plan is progressing well with $500 million already retired. Additionally, we plan to accelerate the retirement of our $485 million senior notes maturing in December. Taking advantage of the no penalty call option, we've elected to retire these notes in September 1 quarter earlier than originally planned, saving $7 million in interest expense in 2025. Another differentiator for Devon is our success on the midstream and marketing front.

After quarter end, we acquired all outstanding noncontrolling interest in Cotton Draw Midstream for $260 million. This transaction gives us 100% ownership of the asset and full access to its cash flows, resulting in savings of over $50 million in projected annual distributions that would have been paid to our partner. These savings are incremental to our $1 billion business optimization plan announced earlier in the year, further improving our multiyear cash inflows. Full ownership of Cotton Draw Midstream strengthens our competitive position in the basin and supports future growth in one of our most prolific areas.

Alongside the Matterhorn pipeline divestiture, this acquisition demonstrates our commitment to creating value and enhancing our E&P operations through our strategic midstream investments. With these transactions, we've successfully created value as both a buyer and seller of midstream assets. Moving forward, we remain open to additional opportunities in the midstream space and creating additional value with our investments. On the gas marketing front, we're focused on maximizing realizations and positioning our gas production to benefit from increasing demand driven by LNG expansion and power generation.

In the second quarter, we executed 2 new agreements that advance these objectives and further diversify our natural gas sales portfolio. The first is a 10-year gas sales agreement to an LNG counterparty starting in 2028, under which Devon will sell 50 million cubic feet a day of natural gas at a Gulf Coast delivery point with pricing indexed to international markets. As LNG build-out creates additional demand for natural gas, we expect to pursue more opportunities to add exposure to international price markers. The second is a Permian gas sales agreement with Competitive Power Ventures Basin Ranch Energy Center to support its proposed 1,350-megawatt power plant.

With an expected start in 2028, Devon will supply 65 million cubic feet per day of natural gas for a 7- year term with pricing indexed to ERCOT West power prices. This pricing construct further limits Devon's exposure to the Waha price weakness we've seen in the basin for some time. Now turning to Slide 9 to touch on guidance. For the second consecutive quarter, we're raising our oil production outlook while lowering capital spending.

We now expect full year oil volumes to range from 384,000 to 390,000 barrels per day, reflecting continued strong well productivity and base performance across our portfolio. Total capital guidance is being reduced by $100 million to a range of $3.6 billion to $3.8 billion. Importantly, our breakeven funding level remains highly competitive at less than $45 WTI, including the dividend. At today's strip pricing, this positions us to generate approximately $3 billion in free cash flow for the year, underscoring the resilience and flexibility of our business model.

I'd also like to highlight the positive impact of the recently passed federal legislation, which provides meaningful tax benefits for Devon. These changes are expected to enhance our free cash flow profile in 2025 and beyond, further strengthening our ability to reinvest in the business and return capital to shareholders. While our tax rate will be somewhat volatile over the next few quarters as we incorporate the new legislation, we now expect our full year 2025 current tax rate to be about -- to be around 10%, down from our previous estimate of 15%, adding nearly $300 million in projected cash flow for the year.

Looking beyond 2025, we expect to no longer be subject to the corporate alternative minimum tax. As a result, we anticipate our ongoing current tax rate will be significantly lower than previous estimates, ranging between 5% and 10%. This reduction will provide Devon with increased cash flow of approximately $1 billion over the next 3 years, assuming a similar pricing environment and capital spend. This is in addition to the $1 billion of incremental free cash flow from our business optimization plan.

Looking ahead to the third quarter, we expect to build on the momentum established in the first half of the year. Our operational execution remains strong, and we anticipate stable production of 387,000 barrels of oil per day. With the capital efficiency improvements and as new wells come online and optimization initiatives take effect, we expect lower capital costs compared to the first 2 quarters. As our teams continue to deliver on key milestones, we're confident that Devon is well positioned to deliver another quarter of strong results and create additional value for our shareholders.

Shifting gears now to talk about the business optimization plan on Slide 10. On the right side of the slide, you'll see a scorecard tracking our progress. As we achieve milestones that generate additional cash flow, we'll update this graph to provide clear visibility into the timing and impact of these benefits. In the course of only 4 months, we've achieved 40% of our $1 billion goal. From the dark blue bars on the graph, you can see the progress we've made by category to date.

This quarter, we're reducing 2025 capital by another $100 million, roughly $75 million of which is directly attributable to our business optimization efforts with the remaining $25 million resulting from deflationary pressures. As Clay mentioned, our drilling and completion teams are leveraging artificial intelligence to drive capital efficiency, while our production teams continue to innovate lift techniques to sustain production levels. On the corporate cost front, we'll retire our $485 million senior notes this year, resulting in $30 million in annual savings to our run rate cost structure. As a reminder, $100 million of the $150 million target in corporate costs will be met with debt retirement.

We expect to achieve this target in the third quarter of 2026 with the paydown of the term loan. Finishing our business optimization discussion on Slide 11. As we've said before, our intent is to be open and transparent with this plan, communicating often. We've included more details here on initiatives underway and milestones achieved. With that, I'll now turn the call back over to Rosy for Q&A.

Thank you, Jess. We'll now open the call to Q&A. [Operator Instructions] With that, operator, please we'll take the first call.

Our first question comes from Neil Mehta with Goldman Sachs.

Yes. I appreciate all the color here today. I would just love your perspective of -- on getting on the non-oil realizations. I think what's clear is you're executing very well on oil.

The netbacks are good on oil. NGLs and local gas prices have continued to be a headwind for a lot of producers, including you guys. And so as you think about the back half of this year and into next year and then some -- even some of the marketing agreements that you announced here today, what are you doing to try to capture better on the non-oil side of the equation?

Neil, it's Clay. Thanks for the question and on the acknowledgment of the good work that our midstream and marketing teams are doing every day. We highlighted a couple of deals this quarter, but it's just -- it's on top of all the other good work that we've done. I'll let Jeff dig in a little bit more on those 2 particular deals, but I think it's a great opportunity just to us to continue to acknowledge the work that we've been doing in this space for quite some time now.

Yes, Neil, this is Jeff. Yes, I appreciate the question. And as you know well, we've talked about this for a number of quarters in a row now. our broader marketing philosophy, specific to our natural gas, and again, the bulk of our natural gas production obviously comes out of the Delaware Basin today, followed by our Oklahoma gas production. But specifically in the Delaware, our approach has been to move those molecules away from Waha, right?

We talked about the weakness that we've seen in Waha for some time. We've been involved with some of our midstream investments and our broader commitment to firm transportation to move molecules away from Waha and to the demand center specifically to the Gulf Coast. So where we sit today, when we look at our Waha exposure, less than 15% of our gas actually has direct Waha exposure in basin. The rest of that, we either hedge our exposure or our firm transportation and our firm sales to our counterparties move those molecules away mostly to the Gulf Coast again.

As we look forward, between Matterhorn and our Blackcomb commitment that we've made, the pipeline that will come on later -- excuse me, in the second half of next year, we're going to be approaching over $1 billion of transport out of basin. So we feel really good about the work -- excuse me, $1 billion -- Bcf a day, sorry, a Bcf a day of transport out of basin, which makes us feel really good about the work the team has done, as Clay mentioned, to really limit our exposure to Waha on a go-forward basis. On top of that, obviously, with the announcements that we mentioned today in our opening remarks, we're always happy to see incremental in-basin demand show up.

And so the CPV power gen opportunity is something that we're excited about. Again, relatively small relative to our production profile in the Delaware, but every bit helps and particularly like the idea of the indexed to the power price, which we're bullish on and think that, again, provides some real diversity to our gas sales portfolio.

Yes. That's great color, guys. And then Slide 10, always helpful to see how you guys are scorecarding across the buckets of business optimization. Just unpack this for us a little bit. How is that 40% that you've achieved in the first 4 months compared relative to your expectations? And what's the next key milestone you guys are really focused on here?

Yes. Thanks for the question. This is Trey. We're really encouraged by all of the advances that we've seen so far.

Obviously, we've made a ton of improvements across several of the categories. And we're going to continue to see a lot of the other categories, the ideas that are being implemented today show up in the financials in the coming quarters. we're -- some of the examples that I would share, we continue to see our teams lean on technology and AI. The way that all of our employees are working today is changing in real time. And we've seen the adoption and the investment that we've made over a number of years really take fire, and we're -- our leadership team has set an expectation and table stakes really that we expect all of our employees to use these new tools, and that's showing up in a lot of these business optimization initiatives that we have across the company.

One that I would highlight is in our production space, and we've got a new analytics that we've just kind of had a breakthrough in the last quarter of how we're tying all of our real-time streaming data from the field into our AI systems and into our agents and allowed us to come up with a new way of how we're analyzing our production faults across the company. This is going to result in millions of dollars of savings, and we've got many of those ideas that are being implemented today that we're going to continue to see grow legs and show up in the financials in the coming quarter.

And Neil, I wanted to pile on that. I want to reiterate something that Jeff mentioned in his prepared remarks. The credibility of this program is really, really important to us. When we announced it back in 4 months or so ago, we knew we weren't going to get an instantaneous credit of $1 billion of incremental free cash flow baked into our share price that we needed to earn it.

And so there's 4 things that I wanted to point out that we have specifically set aside as incremental to this business optimization, the $1 billion of annual free cash flow. So last quarter, we talked about the proceeds from Matterhorn. We are not claiming credit for that in our business optimization model. This quarter, we talked about CDM and the benefits associated with $50 million plus of dollars not going out the door that we are not claiming credit.

In addition, we've talked before about the deflationary dollars that will not accrue to this tally as well. And then the really big one this quarter is the taxes. Obviously, $300-plus million a year will absolutely enhance our free cash flow, but we're not claiming credit on this business optimization for those 4 important things. So think of it this way, we're going to achieve the $1 billion of incremental free cash flow by the end of next year in a sustainable, ratable way each year going forward, plus these other very, very significant items.

And so I think the credibility is worth underscoring about 3 times just to make sure that you guys are hearing us. We're trying to be as transparent and open as we can on this and really holding ourselves accountable to achieving some really big things. And what I would tell you is the team is crushing it. So thanks for the question.

Our next question comes from Scott Gruber with Citigroup.

It's nice to see the full year oil volumes ticking higher here. Does the improvement in the output drive you to shift higher how you think about the maintenance level of production in '26 to use the new run rate from this year?

Yes. Thanks for the question, Scott. Look, we -- obviously, next year is a little still too early to talk about. We're not providing guidance yet.

But obviously, we're doing the work. The work that we do this year really sets up the work for next year. And what we're still doing is goal seeking for that kind of mid-3.80s as the right run rate going forward. So don't think of this as a reset.

We're going to have some quarters that are a little hotter and a little bit lower, but we're still running kind of that mid-3.80s as the right oil rate for us. So this is not a reset going forward.

Well, I guess with the production enhancement efforts, would that not tick higher? Kind of why keep it at the mid-3 80s? Or is that just kind of baking in some conservatism?

Yes. So obviously, we're thinking a lot about the macro. We feel like the oil market is just generally well supplied. And what that translates into us is that we think maintenance capital is the right approach from an investment standpoint.

So as we accrue benefits on the production side, on the capital side, on the LOE side, what we're attempting to do is accrue those benefits on the cost side of the equation, ultimately in a reduced capital benefit. Now it's hard to do that on a quarter-to-quarter basis. And so you see like we've guided next quarter to a midpoint of $387 million. Don't think of that as a runaway growth.

This is just the incredibly good work of the teams. What we're trying to do is make sure that we balance kind of moderating that activity, so we're not running away on production. But at the same time, we're being very thoughtful about trying to be ratable and smooth in that outlook, and that's what we're solving for when we're looking at '26 and really beyond. Yes, John's got one other point.

Yes. And I think just to add to Clay's comments, the downshift in rig and horsepower count that you saw us announce in Q1 is reflective of that. So as we have these production optimization gains, a lot of times, they show up in a lot of small ways and we see it more in real time. And to Clay's point, we see that in the next quarter.

And so that's the reason you're seeing a little bit higher guide for the next quarter. But the behavior that Clay described really manifests in Q1 and Q2. And you're seeing those rig drops here in the second half of the year, and that's reflective of what I think you'll see us do go forward when we have these production wins.

And think about the benefits of that, Scott. I mean, we are all just cherishing this amazing portfolio that we have. And each time we're able to kind of moderate that activity, flatten that base decline, lower that -- the amount of maintenance capital that's required, that extends that runway even further. So there's many magnitudes of benefit associated with the good work that we're doing on this business optimization.

Our next question comes from John Freeman with Raymond James.

This morning, Landbridge announced a produced water pore space agreement with you all starting in 2Q '27. It looks like you are getting out ahead of what could potentially be an issue in the Permian. I'm just hoping you all could maybe elaborate on that deal and how much runway you see it providing you all.

Yes, John, you're exactly right on us getting out ahead of it. I would just tell you this deal is very consistent with our water management strategy in the Delaware Basin, and maybe I'll hit that at a high level. So first, it's probably worth noting just the magnitude of the water production we have in the Delaware Basin. We're managing at any given time, anywhere from 1 million to 1.2 million, 1.3 million barrels a day.

And so the first call on that water really for us is our water recycle and reuse Depending on how many frac crews we have running at any given time, how much third-party water demand may be out there, we can send maybe 25% to 35%, maybe on a really good day, 40% of our water back to recycle, and we'll reuse that in our operations. But beyond that, we've got to manage that water. And we've done a couple of things over the past few years to be really proactive in that space. One was our joint venture with WaterBridge, predominantly on the Texas side of the basin.

We've since expanded that partnership a bit on the New Mexico side. The other thing that we've done and more predominantly on the New Mexico side is continue to build out our infrastructure into what we call a super system. And specific to New Mexico, we now have the ability to move water from asset to asset bidirectionally. It gives us a lot of flexibility.

And then what we do on the back end of that is we have a lot of strategic partnerships with third parties to be able to move that water around. And so the deal that you saw announced this morning is simply one of those strategic relationships with a third party. We've really leveraged a WaterBridge JV to be -- to allow us to do that. And so in 2027, when that deal really becomes effective, we'll now have the ability to move that water to a part of the basin that's much lower in terms of poor pressures in the Delaware Mountain group.

And so I see this as a strategic advantage for Devon going forward. It's a win-win for our partners on the deal and for Devon.

I appreciate the color. And then just following up on the new gas marketing agreement with CPV. You've got a competitor that's also participating, and they disclosed the right to also purchase power from that facility for their own operations. Do you all have a similar agreement in place?

Yes, John, I appreciate the question. We have not negotiated an agreement to purchase power from them at this point in time, but that's absolutely something that our option, frankly, and John can speak to this in more detail. We just don't have the load on the Texas side of the border and the need for it at this point in time as maybe compared to what we're doing on the New Mexico side. John, you want to add some color to that?

Yes, I think that's right. I don't have a lot of color to add there. But over on the Texas side, we haven't fully electrified a number of our facilities, and that includes some of our midstream compression, which would really cause our load demand to be significantly higher. To that, we also have dedicated substations on the Texas side, good partnership and relationship with Encore.

So on a relative need basis, that's not simply something that we have as much of.

Our next question comes from Paul Cheng with Scotiabank.

Maybe [ Kate ] if we -- can we look at Bakken? Maybe that the data is wrong, but it does look like the well productivity is maybe come down a bit and also from the third-party data. So can you give us some idea that are we seeing that it's just a dip or that the deterioration is something that need to work on? And also whether you have a sufficient scale now after the Graceam acquisition that you think you have?

And the second question is that on Eagle Ford, that after the dissolve of the joint venture, can you give us some idea that now you reset -- I suppose that you reset the base? And how is the cadence on your activity and also your production outlook for that over the next several quarters?

Yes, Paul, this is John. I'll do my best to answer both those questions. So starting in the Williston, really, the phenomenon you're seeing there is back in what would be probably some of the newer public data you're seeing coming from Q4, that was largely our Missouri River pad on the east side of the basin, which is our legacy asset. Simply put, the geology is higher quality there.

You're going to see more productive wells. So as we've shifted our activity over to the west side of the basin on the newly acquired Grayson asset, on a relative basis, you're going to see well productivity be a bit lower. What I would tell you, though, relative to our expectations, our well productivity has been quite good on the west side of the basin. So very consistent with our expectations and really no concerns on our part with Williston well productivity.

I think second, on your question on the Eagle Ford, if I heard you correctly, yes, there's absolutely been sort of a reset on our production there. As we closed the BPX dissolution on the first day of the quarter, BPX took a disproportionate amount of the production on that deal while we took more of the upside. And so really, when you look post-BPX dissolution closure. We've got about 55 more wells that we want to bring on throughout the course of the year on that asset.

It's about 90% in DeWitt County on the Blackhawk field, formerly part of that JV. And we feel really good about our ability to continue to grow production back to the levels sort of pre-split.

Our next question comes from Scott Hanold with RBC.

Jeff, you kind of mentioned the windfall you all are going to get from the OBBVA. I think you said $1 billion over the next few years. What is the plan on allocating that cash? Like what are you targeting to do with that?

Could that be for incremental shareholder returns? Do you -- would you rather focus on maybe paying out the term loan faster? But just give me your thoughts on how to allocate that.

Yes, Scott, it's a great question, and I appreciate you highlighting the optionality that we're going to have with the incremental free cash flow, really a great position to be in on a go-forward basis. When we look at our financial framework and shareholder return kind of approach, there's, as of today, no change to that going forward. So as you know, the priority there is for us to grow and sustain our fixed dividend is kind of the first priority. We've set out a range on the share repo by quarter of about $200 million to $300 million per quarter.

We don't expect to change that at all. And then, of course, as you know, we've got the $2.5 billion debt reduction target out in front of us as well. So as we accrue this incremental free cash flow from our business optimization game plan, from the tax savings that we've seen or expect to see, that will accrue to our balance sheet and will likely accelerate some of the debt reduction that we have planned here over the course of the next 18 months or so.

Okay, I appreciate that. My follow-up is on the Anadarko. And Paul highlighted, obviously, there are some moving parts on both Bakken and Eagle Ford production. But I think Anadarko stepped up pretty strongly this quarter as well.

Can you tell us where you all are with the JV there and how to think about that production? And obviously, it's got a little bit more of a gas mix. So it'd be interesting to hear your kind of thoughts on investing in that area and your views on the gas macro.

Yes. As far as the Anadarko, a lot of what we're doing there is really prosecuting our Dow JV. So as you recall, it's a 49-well commitment we kicked off, I believe, here in the second quarter. And so we've been prosecuting that activity with that.

The production growth that you've seen sort of quarter-over-quarter there would have largely been tied to the new well IDs associated with that activity. Now we'll say relative to Q1, we did have some weather impacts in Q1. So the growth probably appears to be a little bit more than what it otherwise would be. But we've been consistently running rigs in that basin now for much of the year. I'd say the activity is pretty consistent.

Our next question comes from Doug Leggate with Wolfe Research.

Clay, can you hear me okay?

Thank you, Doug. I can hear you fantastically.

Okay, great. I just wanted to check that there were no connection issues this time around, so thanks for your patience.

I sincerely appreciate you checking.

That's good stuff. You have no idea how many times I said that last time around. But anyway, I did actually want to ask a question last call, and I didn't get to for some reason. And it was about the BP separation.

And I want to address one specific issue. When BP talks about this, they said that they chose their acreage because they had problems with the Wilcox and the stability of the Wilcox sand in the eastern part of the play, which caused sidetracks, all sorts of operating problems and so on, and they wanted to avoid that going forward. I wonder if you could address that as it relates to your experience of operating in that part of the Eagle Ford. And I've got a follow-up for Jeff, if that's okay.

Sure, Doug. Happy to address that. So I mean, this is a classic win-win. I think BPX was really happy to get the acreage that they did and satisfied some of the objectives that they had.

As John mentioned, they've got a disproportionate share of the production day 1. But I can tell you, we were equally happy to get the acreage that we did. We have more running room, more upside. We've seen this very material savings in capital cost that completely changes the game. We feel very confident in our ability to execute as you move to that Northeast area.

It is more challenging drilling, but we are much more confident to having our D&C team jump all over that. We see a lot of runway. We've executed that. We didn't have the slide this quarter.

But if you look back at last quarter, we showed as we continue to move and take over these material savings are real. As we continue to move to the Northeast, there's an extra step that we will take in regards to casing string. But what it does is at this lower cost structure, it continues to open up significant runway, and we just see so much more upside. So it's one of the things that we are super excited about.

The team has done an exceptional job on executing on some of the objectives that we had, as I mentioned in my prepared remarks, our stated goal was north of $2 million. We had kind of whispered. We really think it's $2.7 million. We've now achieved that $2.7 million per well.

And as you know, that changes the game on the upside potential of that runway. And even the more challenging acreage to the Northeast, we just have so much more running room and so much more upside value to create from there.

Clay, that saving includes the additional string?

Yes. So the wells that we're comparing apples-to-apples, that is -- that's the $2.7 million. But we needed to be able to achieve that as we move to the Northeast. Most of those wells are going to be the same casing design.

But where we apply the incremental casing designs, they were cost prohibitive before, and so just had no value in our portfolio. with this improved savings, even if we have to add an extra casing string, which would require some extra cost, these remain value creative and accrue to the positive on NPV for us. So that incremental casing string, where necessary, is incremental, but know that, that overall savings still allows these wells to be competitive in our portfolio.

That's great. So my follow-up, Jeff, I guess there's a couple of pieces to this, and it starts with cash tax. You've given the next 3 years. My question is, I know it's not -- there's no precision here, but this idea that you now get IDCs on a kind of, I guess, as long as the current administration is in place for an extended period of time.

What does it look like beyond the next 2 or 3 years? And I guess my part B would be, clearly, this is kind of a windfall. I think I heard you say that you're prepared to put cash on the balance sheet and reduce net debt. Am I overthinking that?

No, that's exactly right, Doug. Yes, as we continue to -- and obviously, the tax is impactful, but also the free cash flow we're going to generate with our business optimization game plan and some of the other things that we've talked about here today that Clay mentioned previously, again, things can change in the world. But based on our current forecast, we're going to be generating significant free cash flow going forward, incremental to what we would have thought of even just a few months ago. And so our game plan is not to change our shareholder return framework at this point in time, accrue that cash to the balance sheet help us achieve that $2.5 billion debt reduction that we set out on the back of the Grayson Mill acquisition.

So that's absolutely our current thoughts around how we're going to allocate this capital going forward. And again, as we work through our capital budget here over the coming months, we'll obviously provide some incremental guidance on 2026 and things may change a bit. But the current thought process is continue to work towards that $2.5 billion debt reduction beyond the cash return to shareholders. To your question about longer-term kind of tax profile, as I highlighted in my opening remarks, the benefit of TMT going away from -- the corporate altman tax going away for us as a result of the IDC deductions, we'll have a tax rate -- a current tax rate closer to that 5% level as we look at 2026. It will move a little higher in 2027, probably closer to that 10% that I highlighted in the comments.

And then beyond then, again, assuming kind of current price structure, current capital investment, you'll likely see that current tax rate trend higher. But as we look out in our projections, if we look at the current tax rate we had here in the second quarter was obviously elevated with the huge gain that we had on the Matterhorn sale. But if you go back another quarter and see us being in kind of the high teens, we don't get back to that kind of level in our projections until 6, 7 years out, right, under the current construct. So definitely a benefit for us.

Obviously, the bulk of that comes here over the next 3 years with the acceleration of the R&D expensing and the bonus depreciation, but really carries forward even beyond the next 3 years until things level out.

Our next question comes from Arun Jayaram with JPMorgan.

I wanted to follow up, Jeff, on the commercial opportunities or the $200 million that you've realized in that bucket. What is the timing of when you'll get those savings? Is that early in the year? But maybe just helpful because it is a pretty meaningful needle mover to get the timing there.

Yes. So Arun, remember, on the -- I think we talked about this on the last call, we've basically got the contracts executed in place to capture the bulk of that, right, which we've highlighted on our slide in our scorecard. Going forward, there's some incremental to go get, and we'll continue to work that forward over the course of the remainder of this year and into '26 a little bit as well. But that first tranche that we've already highlighted is kind of captured.

Those go into effect at the end of this year. I think it's in the November, December time frame. So you'll really get the full year benefit of that as you look at our 2026 projection.

Got it, got it. I just want to make sure because on the slide, it says it's not captured in your 2025 outlook, but you'll get that later this year.

Yes. And the reason for that is it's not impacting 2025 so it's really a 2026 benefit.

Got it, got it. I got 1 follow-up. Clay, as you have contemplated a higher degree of co-development between the Wolfcamp B and Wolfcamp A zones in the Delaware Basin, I think the mix is going to 30% this year versus 10% last year. I was wondering if you could comment on how you're seeing the interplay between the Wolfcamp B and Wolfcamp A zones and just talk about, are you seeing any impacts to productivity in that Wolfcamp A zone?

Thanks for the question. When we think about these kind of -- these decisions, these are very macro portfolio-oriented. And so when we're doing the trade-off, we're thinking about rate of return, we're thinking about NPV, and we're thinking about quantification of the portfolio and we're trying to balance and optimize all 3 of those. I'm going to kick it to John.

He can talk a little bit more in detail about what we're seeing kind of well to well, and then importantly, how do we plan to continue on this path rolling forward.

Yes, Arun, and Clay, thanks for the setup there because I do think it starts with the trade-offs -- as Clay mentioned, as we shift more into this multi-zone co-development, we know we're taking a little bit of a near-term trade-off on a bit lower well productivity in exchange for a more optimized net present value across our inventory, but importantly, a more sustainable and longer-term inventory runway. And so when you ask the question specifically, is the inclusion of the Wolfcamp B impacting the Wolfcamp A? I would tell you, generally, no, that's not what we're seeing. We've appraised that potential impact now over a couple of years.

We've really optimized both our landings and our spacings to get these large multi-zone developments right. And I'd tell you that the benefit we see is really avoiding the depletion effect on future inventory. And so if we wanted to prop up our well productivity and just mow down our best zones, we could do that. And what we'd probably do is mow down our Wolfcamp A.

But if we did that, we would be sacrificing the productivity of the Wolfcamp B later on. You'd see depletion effects in those wells, and those wells would be lower productivity out in time. So this is a good reason of why we're so convicted in this multi-zone co-development philosophy. So limited to no impacts on the A, but the real win there is we're maintaining the productivity of the B wells.

I hope that answers your question.

Our next question comes from Betty Jiang with Barclays.

It's great to see the operational momentum translating into free cash flow generation. A follow-up to you, Jeff. We talked a lot about the balance of capital allocation. Maybe asked differently, you are grinding out or paying down that $2.5 billion of net debt reduction faster than previously expected with all these efficiency gains, lower CapEx and tax savings.

What do you think is the optimal debt level for this business going forward? We see you potentially reaching that $2.5 billion target by end of '26, maybe early '27. Is that after that, we could see a potential increase in cash return?

Yes, absolutely, Betty. I think that's a great way to think about it. As you and I have talked about in the past, the $2.5 billion debt reduction that we have targeted really does get us to kind of what I think about as our optimal absolute debt level. So if you see, obviously, today, we sit at $8.9 billion of absolute debt.

You take off the $2.5 billion and you're somewhere in the $6 billion to $6.5 billion range. When we run our downside sensitivities around pricing and cost structure, obviously, that net debt-to-EBITDA ratio can flip on you pretty quickly. But at that absolute debt level of $6 billion, $6.5 billion, we feel pretty comfortable and feel really good about maintaining our investment-grade status, which is critical to us for all parts of our business. So I think about that as kind of the optimal absolute level.

And again, I want to reiterate, that's certainly a priority for us. But the benefit of, again, accruing this cash to the balance sheet, and we'll absolutely consider some acceleration of the debt repayment, as I talked about earlier. But that cash on the balance sheet provides us optimal flexibility. So without question, we're going to continue to be talking to our Board about how do we continue to build upon the cash returns to our shareholders.

And so don't take any of my comments as precluding the option down the road of that increasing over time. But certainly, in the near term, the priority is on the debt repayment.

That's very clear. My follow-up is on unlocking the next layer of resources. Given the lower cost structure, whether that's coming from midstream or upstream, do you see other resource opportunities that's getting unlocked now that was previously uneconomical under the prior higher cost structure? If so, like where it could be some of these opportunities?

Yes, Betty, I think the best example that I would point you to there, and we've talked about this on previous calls is our objectives, for instance, in the Powder River Basin. When you look at what we're doing there and what we're trying to accomplish there, I'd say there's really 2 deliverables. One, we want to deliver more consistent and competitive well results. So when you look back to 2024 and what we've done in 2025, we've delivered very consistent results.

In fact, some of the more consistent results in our portfolio. And these are some of the best results we've delivered the Niobrara thus far. The second aspect of our strategic objective there is we've got to consistently lower our well cost. And so when you look specifically at some of these optimizations and the work we're doing, we've been historically north of $13 million on a 3-mile Niobrara well.

We've made a lot of progress. We've gotten closer to, call it, a $12 million type well. And when you look forward at some of the upcoming programs, some of the design changes we're making, some of the scale benefits we'll achieve. We have a vision well concept out there that aligns very well with our business optimization to get to a $10 million type of D&C cost for a 3-mile Niobrara well.

And that's a perfect example of taking something that's marginally competitive in our portfolio today and making it competitive.

Our next question comes from Phillip Jungwirth with BMO.

You mentioned being open to additional investments in the midstream space. And I was just hoping you could expand on this and maybe what part of the value chain that could be. And what's the target level of investment be, assuming you're planning to -- you plan to fund this with Devon's balance sheet?

Yes. Thanks for the question, Phillip. I think what's really interesting about this quarter is you see an example of us highlighting a midstream asset sale and a midstream asset acquisition. And both we're really excited about.

We think they are cost beneficial, structurally beneficial, value-creating opportunities. And so don't think of us as maybe only going one direction on this, but always trying to do the work to find out what is the better scenario to make us a better company. In the case of Matterhorn, we had a tremendous 5-bagger return on that investment. We've held on to the capacity.

And then importantly, we made -- we allowed the pipe to get put into the ground, which was the initial motivation. So check, check, check on that. We retained the capacity. We're doing a really good job there.

When we think about something like CDM, that is one of our highest growth, highest value assets, maintaining control of that. We continue to see gas volumes grow in the area. We see significant upside for that. And then we had an opportunity to take out the rest of it and then lower our cost structure going forward at a very, very competitive investment.

So both of those, although they could appear moving in the opposite direction, the common theme is value creation. Jeff, do you have other comments?

Yes. I would just -- I would echo your comment and just kind of to sum that up, say everything that we do related to our midstream investments is specific to our broader strategy, both on the E&P side of optimizing our business there and creating as lowest cost structure as possible for our core business. And then on the midstream side, as Clay referenced this, it's really a thought process around our broader marketing portfolio and making sure that we can achieve the highest realized price for our molecules in all of our basins. So as Clay gave a great example with Matterhorn, we made an investment there.

And as he said, we're ecstatic with the significant gain that we achieved there. But the real driver of that investment was to make sure that pipe got built and make sure we could get our molecules via firm transport to the demand center. So that's really the broader strategic philosophy, if you will, of all things midstream investment for us.

Okay, great. And then you had strong Delaware production in the quarter and just following up on the co-development question. Now that we're halfway through the year, can you talk about just generally how performance has been versus expectations? Any key learnings so far? And then how optimized do you think you are at the moment as far as overall completion intensity per DSU?

Yes. I'll start with well productivity. So as you heard me mention earlier, we've developed more momentum into our multi-zone development philosophy. I think we've been talking about that for a number of quarters.

When you look at the well productivity from the wells that we brought online this year, I think the public data set right now is Q1. And so what I would tell you generally is those well results are very consistent with our expectations. Now I've also seen some newsletters, some data points, some chatter out there that well productivity is dropping off in a big way. So I do want to provide -- I would caution folks against calling that a trend, and I want to provide a little bit of context around our Q1 data set. So specifically, if you look at it, it's very weighted to the Wolfcamp B or the deeper Wolfcamp as well as disproportionately weighted to the Avalon.

When you look at sort of our total well mix this year for the Delaware Basin, we anticipate 30% to be Wolfcamp B, yet we brought on 60% of our total Wolfcamp B wells here in the first quarter. So what we would really anticipate is returning a bit to a non-outlier, more normalized well mix throughout the next few quarters. With that, we're going to see well productivity increase. So we feel very good about what we're seeing there.

I think your second question was around optimized on completions. This is something that we're always looking at. We're always adopting different completion designs based on what we're seeing with our own appraisal or benchmarking against competitors. There are some completion design changes we're making in certain parts of our areas and other parts, we feel that we're dialed in.

For instance, we were talking to the team just earlier this week about our completion design intensity in one of our zones and one of our assets, and we're going to dial that up based on what we're seeing. So we continue to optimize around completions as well as all aspects of our development planning, which would include landings and spacings and other design parameters.

Our next question comes from David Deckelbaum with TD Securities.

Clay, I wanted to just get back to the initiatives, particularly on commercial opportunities. So far, it looks like the savings achieved have been in the Delaware. Do you anticipate focusing on other areas of the portfolio that might enhance some of the economics, specifically in areas like Anadarko? Or is there more work to be done more in the Delaware from the midstream renegotiation perspective?

Yes, David, for sure, the big wins have been in the Delaware, where most of our activity is. There's an opportunity for active renegotiation there. But we have made wins in Anadarko as well. We continue to focus there.

We see the tremendous gas potential that we just need to unlock more value, make sure we're hanging on to the dollars that come in the door a little bit better. And so I'd say that's another area that we will continue to see accrued benefits.

And I guess, are most of the quantified opportunities that have been captured, are they more a function of better realizations or are you getting materially better rates here?

Yes, David, it's a mix of both. So given the nature of the contracts, depending on where it is and how the contract is constructed, sometimes you'll see that run through our realizations on gas and NGLs, in particular, in the Delaware. But at other times, it will run through GPT. So it can be a little difficult to follow in the financials from time to time.

But absolutely, it's a mix of all the above.

Those are all the questions we have time for today. And so I'll hand the call back over to Rosy for closing remarks.

Thank you, Emily. And I want to thank everyone for your interest in Devon and your participation in our call today. If you have further questions or for those of you who did not get through on the call today, please reach out to Chris or myself. Have a good day.

Thank you all for joining us today. This concludes our call, and you may now disconnect your lines.