Devon Energy - Q2 2023
August 2, 2023
Transcript
Operator (participant)
Ladies and gentlemen, welcome to Devon Energy's second quarter earnings conference call. At this time, all participants are in a listen-only mode. This call is being recorded. I'd now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.
Scott Coody (VP of Investor Relations)
Good morning, thank you to everyone for joining us on the call today. Last night, we issued an earnings release and presentation that cover our results for the second quarter and our outlook for the remainder of 2023. Throughout the call today, we'll make references to the earnings presentation to support prepared remarks, these slides can be found on our website. Also joining me on the call today are Rick Muncrief, our President and CEO, Clay Gaspar, our Chief Operating Officer, Jeff Ritenour, our Chief Financial Officer, and a few other members of our senior management team. Comments today will include plans, forecasts, and estimates that are forward-looking statements under U.S. securities law. These comments are subject to assumptions, risks, and uncertainties that could cause actual results to differ materially from our forward-looking statements.
Please take note of the cautionary language and risk factors provided in our SEC filings and earnings materials. With that, I'll turn the call over to Rick.
Rick Muncrief (President and CEO)
Thank you, Scott. Pleasure to be here this morning. We appreciate everyone taking the time to join us. Devon's second quarter performance can be defined as another one of solid execution on all fronts, as our business continued to strengthen and build operational momentum throughout the quarter. The attractive per-share growth we've consistently delivered quarter after quarter demonstrates the efficiency of our disciplined business model, the quality of our Delaware-focused asset portfolio, and the team's execution capabilities and the benefits of our cash return framework. The slide, the chart on slide four provides a very compelling visual of this success, showcasing our impressive track record of value creation. Since we unveiled the industry-first framework in late 2020, we have deployed $12 billion towards dividends, share buybacks, debt reduction, and accretive bolt-on acquisitions.
The cumulative value of these actions equates to nearly 2 times the value of Devon's pro forma market capitalization from just a few years ago. As you can see from our diversified actions to date, we have carefully designed our cash return framework to be nimble, with the flexibility to allocate free cash flow across multiple avenues to optimize financial results through the cycle. Importantly, this disciplined execution has been rewarded by the market, with our equity performance achieving the highest return of any stock in the entire S&P 500 over this period. Now let's go through some of our second quarter highlights and operating trends in greater detail. Beginning with production, the team did a great job growing oil volumes by 8% on a year-over-year basis in this past quarter.
This result surpassed midpoint guidance expectations and, for us, set a new all-time high oil production record for the company by averaging 323,000 barrels per day in the quarter. Additionally, this volume growth was supported by an infrastructure that includes several strategic midstream assets that we have selectively invested in through the years and have taken equity stakes in an effort to enhance the result from our core E&P operations. A key driver of this record-setting result was higher completion activity in the Delaware Basin. By leveraging the benefits of a temporary fourth frac crew and consistently improving cycle times, we were able to bring online 76 new Delaware wells in the quarter, which was a few more than we originally planned due to efficiency gains.
Importantly, the well productivity from this batch of wells in Delaware was excellent and included a Wolfcamp B appraisal success that strengthens the depth and quality of our resource in the area. We also had a successful redevelopment test in the Eagle Ford and advanced a handful of other interesting appraisal projects across our diversified asset base that it reinforces our confidence in the resource upside that currently exist across our portfolio. Looking ahead, with higher levels of completion activity in the second quarter, we expect our production profile to continue to strengthen the upcoming third quarter. A good visual of this operational momentum can be seen on slide seven, with oil volumes expected to grow to a range of 322,000-330,000 barrels per day in the upcoming quarter.
As I touched on earlier, the capital spending to drive this growth trajectory was a touch ahead of expectations due to very strong execution from our drilling and completion teams that brought forward activity into the quarter. Clay will spend time to cover this topic later, but I am extremely proud to share that we've set several operational records at both the basin and company level, contributing to the record-setting drilled and completed feet per day metrics we have achieved year to date. In addition to our strong operating efficiencies, our business is also beginning to benefit from service cost deflations as contracts are refreshed. This is driven by reduced activity from natural gas-focused companies and private producers over the past few months, resulting in improved availability of services and cost deflation in virtually every category.
Although this is a very dynamic environment, we've observed the most downward pressure to date in the areas of tubulars, rig rates, fuel, and other miscellaneous drilling services that will begin to positively impact our cost structure as we enter the end of this year. We also anticipate price movement with pressure pumping, which is our largest cost category, in the very near future. While it's still somewhat premature to say what and set what our firm outlook for 2024 is, our expectations for deflationary trends should continue. We have the potential for meaningful savings from peak well costs as pricing improvements gradually flow through our cost structure over the next year or so. With the free cash flow model that our business, our business generated, we had another great quarter of cash returns.
We returned $462 million to shareholders through our fixed plus variable dividend, which we have paid out now for 12 consecutive quarters. We also have an active buyback program that resulted in the repurchase of nearly 4 million shares over the past three months. We believe this balance between dividends and buyback offers investors the powerful combination of an attractive yield and steady per-share growth through the cycle. Now, moving to slide 11, with the progress that our business has made year to date, we are well on our way to meeting the capital objectives associated with our 2023 plan. The momentum we have established places us on track to deliver a production per share growth rate of approximately 9% for the year.
Importantly, the activity required to fund this growth is self-funded at a $40 WTI price, or approximately half of where we are today, and is delivering returns on capital employed greater than 20% at today's commodity prices. While once again, it is too early to provide firm guidance for next year, the trajectory of our business sets us up for a strong outlook in 2024 as well. Given current market fundamentals, we plan to invest at levels that will sustain our productive capacity, and any improvements that we see from lower service costs will accrue to our shareholders in the form of higher free cash flow generation. This discipline, pursuit of value over volume, positions us to continue to deliver another year of differentiated cash returns and highly competitive returns on invested capital versus the broader market.
Now, with that, I'll now turn the call over to Clay to cover our operational highlights. Clay?
Clay Gaspar (EVP and COO)
Thank you, Rick, and good morning, everyone. Our second quarter operating results demonstrated that our business is performing at a high level and building momentum as we head into the second half of the year. As Rick touched on, this positive trajectory is underpinned by improving capital efficiency from faster cycle times, improving service costs, and positive appraisal results that will contribute to our production profile and financial results over the balance of this year and more significantly into 2024. Today, I plan to provide a brief overview of the second quarter results across our assets, as well as highlight some upcoming catalysts. The most significant contributor to Devon's second quarter operating success was once again our franchise asset in the Delaware Basin.
As you can see on slide eight, more than 60% of our capital activity was deployed to this prolific basin, allowing us to run a consistent program of 16 rigs. With a fourth completion crew at work in the first half of the year, we were able to place 76 wells online in the second quarter, up more than 80% compared to the first quarter. This elevated completion activity grew our Delaware production to 420,000 BOE per day and is expected to underpin volume growth in the third quarter as well. While we had great results across our acreage position, a key project I would like to highlight from the quarter was our Mule development in Eddy County, New Mexico. We've talked in the past about the important appraisal work that we do each year with 10%-20% of our capital budget.
The Mule pad is an example to provide you some visibility into the fruits of this labor. This 11-well project successfully co-developed multiple landing zones within the Wolfcamp, with particularly exciting results from the appraisal of deeper Wolfcamp B benches. The initial results from these six wells targeting the Wolfcamp B landing zones average greater than 3,100 BOE per day, with 44% oil cut. Per-well recoveries are on trend to exceed 2 million barrels of oil equivalent. Importantly, these highly commercial appraisal results de-risk and enhance the economic expectations on approximately 100 Wolfcamp B locations in the Cotton Draw area. Furthermore, these deeper Wolfcamp locations are expected to be highly competitive within our capital allocation framework going forward. The Delaware team also continued to make progress advancing drilling and completions efficiencies across our operations in the basin.
In the Wolfcamp, we improved drilling productivity by about 10% on a per-foot basis over the past year, while some of our best spud release times for 2-mile laterals pushing below 15 days. Completion efficiencies have also steadily improved, with our cycle times decreasing by 9% year to date and compared to 2022. Averaging a record completion pace of more than 2,200 feet per day in the quarter, this operational progress has been accomplished in conjunction with an even higher safety and environmental focus and expectation. The great work our team has done to drive improvements across the entire planning and execution of our resources, coupled with the broader service cost deflation trends, are positioning our business to be even more efficient as we head into 2024.
Moving to the Eagle Ford, our 3-rig program resulted in 29 gross wells placed online during the quarter. This activity, which was concentrated in the recently acquired acreage in Karnes County, drove a 9% increase in productivity versus the previous quarter. This margin, this high margin growth was driven by strong well productivity achieved from a balanced mix of development and appraisal activity designed to refine the next stage of development for this prolific resource play. Our top development project in the quarter was headlined by our L.P. Butler pad. This 4-well pad developed a highly charged seam of pay in the volatile oil window of the play that exceeded pre-drill expectations, reaching an impressive average 30-day rate of 3,600 BOE per day with a 56% oil cut. On the appraisal front, a key success in the quarter was the Cedarwood unit.
This development project in Karnes County tested infill spacing ranging from 140 to 150, excuse me, 180 foot and roughly 30 wells per section. The initial 30-day rates from this package of wells averaged 2,000 BOE per day, resulting in highly commercial returns that adds to the depth and quality of our inventory in the play. Also, adding to the commerciality of this tighter spacing was our drilling performance, where we broke a company record averaging over 2,000 feet per day, which included the fastest spud to rig release time in the company history of only 5.7 days.
As we look to allocate capital for 2024 and beyond, the positive operating results we've achieved year to date served as valuable data points to optimize future development activity in the Eagle Ford and further deepens our convictions of the resource upside that exists across this entire field. Moving to the Williston, volumes began to rebound in the second quarter, growing 4% quarter-over-quarter to 56,000 BOE per day. This growth was driven by improved weather, higher up times on existing producers, and successful adjustments to completion and production techniques for some of the new well activity. These completion and production modifications consisted of change to a larger proppant size designed to mitigate mobility of sand and a shift in artificial lift techniques to improve well uptime.
With the favorable flowback results on two pads that have deployed these techniques, we have high confidence that the wells' productivity will improve as we see progress throughout the year. Looking at inventory, we now have more than 150 wells remaining and identified significant refrac opportunities across hundreds of producing wells in the field, providing us the optionality to deploy steady reinvestment in this play for multiple years to come. Turning to the Powder River Basin, the key objective of our 2023 program is to continue to appraise and methodically refine our understanding of the Niobrara so that we can optimize this resource for future development. With this focus, the team has made substantial progress over the last year, establishing repeatable commercial results with 3-mile laterals across a significant portion of our acreage in Converse County.
Furthermore, since we're not observing any degradation in the results from three well spacing, we plan to test four well per section later this year. Lastly, we're also encouraged by the early flow rates from appraisal activity recently brought online in the northern portion of our leasehold position that could extend the Niobrara potential into Campbell County. I'll provide more updates on these tests in the coming quarters, but it's been evident that our 300,000 acre net acreage position in the Powder River Basin is providing Devon important resource catalysts for the future. Lastly, in the Anadarko Basin, production volumes grew 10% from the previous quarter, driven by the ramp-up in completion activity funded by a drilling carry from our Dow joint venture.
The operational execution from this program was superb, with well costs consistently coming in below pre-drill expectations and the initial flow rates from several wells exceeding 3,000 BOE per day. To date, we have only utilized approximately half of the 133 well carry agreement we have in place with Dow. We anticipate the remaining carry will provide us sufficient runway to support our current pace of activity for the next 18-24 months, and we're open to expanding this scope of partnership, as we've successfully demonstrated in the past. For the remainder of 2023, we plan to bring on 10 new wells weighted towards year-end. In summary, I'm proud of the capital efficiency results that each of our asset teams are delivering during the quarter and the strong momentum that we have built heading into the second half of 2023.
With that, I'll turn the call over to Jeff for the financial review. Jeff?
Jeff Ritenour (EVP and CFO)
Thanks, Clay. I'll spend my time today covering the key drivers of our second quarter financial results and provide some insights into our outlook for the rest of the year. Beginning with production, a key driver of second quarter volumes exceeding midpoint guidance was efficiency gains that compressed cycle times, leading us to capture a few more days online than planned. Looking ahead, the benefits of higher completion activity from the Delaware in the first half of the year is expected to drive volumes, oil volumes higher in the upcoming third quarter and leaves us on track to meet our volume targets for the full year as well. On the capital front, we've invested 55% of our budget year to date. This weighting to the first half of the year is due to higher completion activity, driven by a fourth temporary frac crew in the Delaware Basin.
With this temporary crew recently released, we expect a lower capital spending profile as we head into the second half of the year and remain confident in our capital spending guidance range for the full year. Regional oil pricing once again remains strong, with realizations near WTI benchmark levels in the second quarter. We're also seeing strength in the oil price curve for the second half of 2023. This positive trend is providing a meaningful impact to our returns and cash flow generation capabilities, with every $1 uplift in WTI resulting in about $100 million of additional annual cash flow for the company. Despite the strength we saw in oil pricing in the second quarter, we did experience weakness in both natural gas and NGL realizations.
We do expect improved markets for gas and NGLs in the second half of the year, which should translate into better price realizations for us across the portfolio. Moving to operating expenses, our field-level costs were right in line with expectations for the quarter. However, we do expect a minor uptick in per-unit cost in the second half of 2023, driven by a recently executed water handling joint venture in the Delaware Basin. Our new water JV provides us significant operational flexibility through enhanced scale and multiple disposal options. In addition, the JV materially lowers our future midstream capital requirements in the area. Looking forward, our equity stake in the JV will provide us distributions over time, offsetting the incremental operating cost at the asset level. We could also choose to bring forward value by monetizing this asset at some point in the future.
Cutting to the bottom line, we generated $1.4 billion of operating cash flow during the quarter. Combined with the low reinvestment rates to fund our disciplined capital program, we were able to generate free cash flow for the 12th straight quarter. Furthermore, we've delivered these results across a variety of market conditions, showcasing the durability of our business strategy. With this free cash flow, our top priority was the return of capital to our shareholders. A key use of our excess cash in the quarter was the funding of our fixed plus variable dividend, with the board declaring a payout of $0.49 per share. This distribution will be paid at the end of September. In addition to dividends, we also see great value in our equity and continue to be active buyers of our stock.
During the quarter, we repurchased an additional $200 million of stock, bringing our year-to-date total to approximately $750 million. With the authorization we have in place, we remain on pace to repurchase approximately 9% of our outstanding shares by the end of next year. These opportunistic buybacks are a critically important tool for us to compound per-share growth for investors over time. To round out my prepared remarks this morning, I'd like to give a brief update on our investment-grade financial position. We exited the quarter with $3.5 billion of liquidity and a low net debt to EBITDA ratio of 0.7 times. This leverage resides well below our mid-cycle leverage target of 1 time or less.
Subsequent to quarter end, we took the next step in improving our financial position by retiring $242 million of debt at maturity. With the strong cash flow our business is generating, we'll have additional opportunities to pare down our debt and maturities coming due in 2024 and 2025 as well. With that, I'll now turn the call back to Rick for some closing comments.
Rick Muncrief (President and CEO)
Thank you, Jeff. Good job. I would like to close out today by reiterating a four key message from our prepared remarks. Number one, our disciplined execution in the second quarter demonstrates our business is performing at a high level and building momentum as we head into the second half of the year. Number two, this positive trajectory is underpinned by better capital efficiency from higher and faster cycle times, strong well productivity, and improving service costs that will contribute to our financial results over the remainder of this year and into 2024. Number three, our resource base continued to strengthen this quarter. This was evidenced by our highly commercial appraisal results in the Deeper Wolfcamp and a positive redevelopment test in the Eagle Ford that adds to our conviction of resource upside across our portfolio.
Number four, with this advantaged resource base, we are deeply committed to a disciplined pursuit of per share value creation over production volume growth. Foundational to this commitment is our carefully designed cash return framework that has the flexibility to allocate free cash flow across multiple avenues to optimize shareholder value through the cycle. Now, with that, I'll turn the call back over to Scott as we get into Q and A. Scott?
Scott Coody (VP of Investor Relations)
Thanks, Rick. We'll now open the call to Q and A. Please limit yourself to one question and a follow-up. This allows us to get to more, more of your questions on the call today. With that, operator, we'll take our first question.
Operator (participant)
Thank you. With our first question comes from Neil Mehta from Goldman Sachs. Neil, the line is now open.
Neil Mehta (Equity Research Analyst)
Yes, thanks so much. The first question is just on, on the production profile for the back half of the year. As you, as you indicated, you guys are focused on value over volume, but some of the pushback we've gotten this morning has been centered around, you know, volumes being a little bit below consensus for the back half of the year. Maybe your thoughts on thoughts on whether there's some conservatism in the way that you, you model this out, and, and where are areas potentially that could surprise the upside? Thanks.
Clay Gaspar (EVP and COO)
Hey, Neil. Thanks for the question. This is Clay. you know, just wanna reiterate, we feel good about our full-year guide. Certainly with the accelerated activity, things moving a little quicker on the D&C front, that pulled a little bit of our production forward. That's great on a per-well basis, but you get a little bit of lumpiness in the productivity. We pulled some of that third quarter volume forward, so we, we maintain our full-year guide, but we've always seen kind of a roll as we pull back from that 4-frack fleet in the Delaware to the third. Nothing new, nothing unplanned, but consistent with what we've been showing, and once again, feel real good about the, the full-year guide.
Neil Mehta (Equity Research Analyst)
All right. That, that's great. The follow-up is just, can you talk a little bit about this water handling contract in Delaware? There's a modest bump up in the LOE in the guide. A little bit of background on what it is and how we should think about it.
Jeff Ritenour (EVP and CFO)
Neil, this is Jeff. Happy to do that. We're excited about the flexibility and the, and the scale that that's gonna bring to our water handling in the basin. You know, we're gonna have, you know, multiple disposal options as opposed to what, what we had before. It does bring a little higher operating costs at the asset level, but as I mentioned in my prepared remarks, with the equity stake that we've got in the joint venture, we'll be receiving distributions on a go-forward basis, which is gonna more than offset that, that additional LOE cost that we're gonna see. As, as I'm also mentioned in the prepared remarks, we also think it provides us a great opportunity, you know, with that equity position, to monetize the asset at some point in the future.
I'm really excited about the flexibility it gives to us operationally. As Clay will attest, there's certainly a fair amount of water we got to move out in the Delaware Basin. This additional, you know, flexibility and scale, we think is gonna be a real positive for us. I'll also add, you know, it certainly helps us on the capital efficiency front because it helps us to eliminate a pretty material amount of capital that we otherwise would have had to spend on water infrastructure as you look out over the next couple of years.
Neil Mehta (Equity Research Analyst)
All right, guys. Thanks a bunch.
Rick Muncrief (President and CEO)
Thanks, Neil.
Operator (participant)
Thank you. Our next question comes from Nitin Kumar from Mizuho. Nitin, your line is now open.
Nitin Kumar (Senior Analyst of U.S. Oil and Gas Companies)
Hi, good morning, Rick and, and team. Glad to speak to you. You know, Rick, you've kind of mentioned a little bit of a acceleration of activity into the first half. It's, it's a little bit different than what you had said, when you gave the guidance for the year. It does imply a little bit slower cadence of completions in the second half of 2023. I, I'm just wondering: Could we use that as a baseline for 2024, in terms of activity levels?
Rick Muncrief (President and CEO)
You know, Nitin, I'll tell you what. What we like to do is we think the most important thing for us is, we, we like the consistency. As you think about quarter-over-quarter, we've been pretty consistent for, for a while on our, on our production, and we like to look at things on an annual basis. Clay mentioned the fact that, that, you do have some lumpiness from time to time, just through acceleration. You could have working interest changes, you could have, some assessment work. You do all sorts of things like that. But I think for us, the most important thing, Nitin, would be that let's just look year-over-year.
And I know that we, people like to look at things on a quarterly basis, but from my perspective, I wanna watch that year-over-year profile, and let's, let's lean in on share repurchases, and let's, let's make sure that we get that growth on a per-share basis. Clay, is there anything else you wanna add to that?
Clay Gaspar (EVP and COO)
Yeah, Rick, I, you know, Nitin, your question was, should we expect that run rate? Just remember, that fourth frac crew in the front half of the year, we are consuming DUCs, essentially, in that period. Just if you look at Delaware Basin, and then when we're running three frac crews, as we will in the second half of the year, we're essentially generating DUCs. In a fully optimized world, we would pick up and drop that, that fourth spot crew to optimize. I would say in today's world, what we're doing is really trying to bring that crew in, get them fully up to speed, let them run through the opportunities that we have, and then put them on pause, in this case, for about six months. We'll pick them back up again in January.
Jeff Ritenour (EVP and CFO)
You'll see capital tick up, but you'll certainly see the production tick up as well, related to that crew. That does exacerbate the, the lumpiness, that we talk about. I'd love to have a straight line, again, when you pan out and look at an annual basis, like Rick talked about, you really see the consistency of our, of our program.
Nitin Kumar (Senior Analyst of U.S. Oil and Gas Companies)
Great. Thanks for the color, Rick and Clay. I guess for my follow-up, you know, we've seen some private assets change hands here in the last three months or so. The shape of the Delaware Basin has changed a little bit. You've previously talked about scale and the importance of that to the new business model that Devon initiated three years ago. Just any thoughts on the M&A market going forward? Do you see room for consolidation here, and what is the role that you think you might play?
Rick Muncrief (President and CEO)
You know, Nitin, that's a great question. I think we've talked about this, fairly consistently. You know, as, as far as consolidation, I think, A, it's gonna continue to happen. I think as you start looking across many companies' portfolios, and we're not one of those companies, but there's a lot of companies out there, many of the smaller companies, they're, they're gonna start looking for, for options, because they are getting light on inventory. You know, some of the private consolidations that, that we've seen recently that you're referring to, many of those were companies that, that exhibited performance. It was really.
You know, quite honestly, it was, pretty impressive in how fast they grew their production, how fast they were going through that inventory, they also see, the challenge, of where they're gonna go in the future. For companies like us, we're gonna be very, very disciplined, and, we, we just haven't had an appetite to, to really take on that, that steep decline rate that you would be inheriting. You have to be very, very thoughtful, and it gets, it gets to be tricky. I, I will say there were some, pretty creative, solutions with some of those companies that had those, in, in bringing some, you know, two and three companies all together to make some, some, pretty, pretty interesting, transactions. I think it just represents the creativity in our sector.
I think you're gonna continue to see consolidation. I think it makes a ton of sense, and it's gonna happen for, for, numerous, numerous reasons. Over time, you'll continue to see companies, consolidate, and there will be, there will be companies such as Devon, I believe, that, will be the beneficiaries of those because we're gonna be very disciplined, and I think we'll try to, be opportunistic and make sure that we make moves that, that just build a stronger and stronger, stronger, more durable, company. But you're, you're spot on. I think consolidation in our industry is gonna continue.
Nitin Kumar (Senior Analyst of U.S. Oil and Gas Companies)
Great. Thanks for the answer, Rick.
Rick Muncrief (President and CEO)
Thank you, Nitin.
Operator (participant)
Thank you. Well, our next question comes from Scott Gruber from Citigroup. Scott, your line is now open.
Scott Gruber (Managing Director and Senior Analyst)
Yes, good morning. Curious, you know, about the returns you're seeing on the, the refrac wells in the Eagle Ford? How do those compare to a, a new well in the basin? You know, how does that influence, you know, how you prosecute that, that program going forward?
Clay Gaspar (EVP and COO)
Yeah, thanks for this question, Scott. This is Clay. We're really excited about the, the work that we've seen to date. We have about 30 tests. You know, we're still learning on what's the right wells to go in and refrac, what's the right techniques to go in and, and prosecute those. I would say, you know, for only being 30 wells in, 30 refracs in, we're very encouraged about the results. We're encouraged about the inventory that we had. You know, I should note, in the Validus acquisition we did, we had zero refracs underwritten in the, in the acquisition price, and now we're seeing more material upside, both in redevelopment and in refracs. I would say on a heads-up basis, when you think about returns, the better ones certainly compete heads up with, the wells that we're drilling today.
You really have to really think about how do you prosecute those, the right approach, and you'll end up getting a variety of them. So I would say it's too early to tell on an exact quantity and the overall return, but certainly the top half of what we've de-risked today, we feel really good about, and it will certainly become more of a regular part of our, our investment opportunities on an annual basis.
Scott Gruber (Managing Director and Senior Analyst)
I appreciate that, Clay. Just a, an unrelated follow-up, but, you know, I did notice that, you know, the gas feed on the quarter, at least versus our numbers, was largely driven by the Anadarko and a bit by the Williston. Was anything going on in, in those basins, that led to a, you know, a gas production step-up? Are you seeing the, you know, the gas-oil ratio of the base, there step higher? Just some, some color, you know, on the, on gas production, Anadarko and Williston would be great.
Clay Gaspar (EVP and COO)
Yeah, thanks for that. The, the Anadarko Basin certainly is our, our gassier option. We have a lot of running room right now. We're more focused on the liquids-rich portion of it. Even, you know, relative to the rest of our portfolio, that's certainly a gassier part of the mix. When we look to the, the wells that we're developing in Williston, a little bit higher gas cut there as well. Very importantly, we're doing a good job of getting that gas down the line, through the meter, and sold, rather than flaring. Happy to report our flaring numbers continue to be heading in the right direction around the company, especially in Williston, and that's certainly not without challenges. I think that's the bigger contributors to the increase in gas.
You know, getting that through the meter, getting that sold is, is always a very high objective, but we're also really focused on the oil side of the equation, which is where our revenues really come from.
Scott Gruber (Managing Director and Senior Analyst)
I appreciate the call. Thank you.
Operator (participant)
Thank you. With our next question, it comes from Arun Jayaram from JPMorgan. Arun, your line is now open.
Arun Jayaram (Research Analyst)
Yeah, good morning. I, I know you guys aren't-
Rick Muncrief (President and CEO)
Good morning Arun.
Arun Jayaram (Research Analyst)
Yet ready to kinda. Good morning, Rick. I, I know you guys aren't yet ready to provide more, you know, specific called soft commentary on, on 2024, but I did wanna get maybe some of your early read on 2024 CapEx. You know, if we look at your second half 2023 CapEx guidance, it's around $1.7 billion or $850 million a quarter. If we annualize that, that would be about $3.4 billion. It sounds like you would, would need a, you know, call it a, a partial fourth frac crew, to, to execute your 2024 plan. I, I just wanted to, to say, if those are kind of the elements, should we be thinking about CapEx in the mid, call it $3.5 billion range? Again, just wanted to get some preliminary thoughts.
Clay Gaspar (EVP and COO)
Yeah, appreciate that, Arun. I, I think your, your logic on how to get there as far as rig count, frac fleet count, I, I completely agree with. I'm gonna hold back on, on giving you a number for next year. There's a lot of things going on around what's happening in commodity price, therefore, rig count, therefore, inflation, deflation. Those things have pretty material impacts, and we're just gonna hold back. I think directionally, think of the same similar activity as a really good starting point.
Arun Jayaram (Research Analyst)
Great. My follow-up maybe for, for Jeff. Jeff, I wanted to kinda zero in on the Williston Basin. This is called the third quarter in a row that we've seen relatively low realizations in for natural gas and NGLs. I just wondered if you could provide what's going on there, and is this gonna be a persistent impact to you going forward?
Jeff Ritenour (EVP and CFO)
Yeah, Arun, this is Jeff. Yeah, appreciate the question. As Clay mentioned earlier, there, particularly in the Williston, where, where you've got some gas, is obviously not the lion's share of the, of the production mix, but, can be a real challenge, obviously, to move the gas up there, given the infrastructure and the, and the constraints that we have. I, I would tell you, when you look at those realizations, in particular in the Delaware, or excuse me, the Williston, you're gonna see some, some wild volatility, just given the, the, the deducts that we have from a realization standpoint. And so it's not gonna be as clean and as consistent as you would, would usually see in, in some of our other basins.
I'd also point out, as, as you're well aware, it's, it's pretty immaterial to, in the grand scheme of things, given the margins that we see from the oil barrels there.
Arun Jayaram (Research Analyst)
Fair enough. Thanks a lot, Jeff.
Operator (participant)
Thank you. Well, our next question comes from Neal Dingmann, from Truist. Neal, your line is now open.
Neal Dingmann (Managing Director of Energy Research)
Good morning, Neal, thanks for the time. My first question, guys, is on the, your Delaware Basin. Specifically, maybe Clay, could you speak to what benefits that recent Wolfcamp B appraisal success might have on, I mean, maybe it's too early to say what it might have on total production, but maybe what, what you think the upside will that, that could drive in the, you know, I don't know, later this year, next year? Just wondering how you view also the benefits, you've touched on this earlier on your comments, how you view the benefits of bringing some of those wells forward this year? Not, not the appraisals, of course, but the others.
Clay Gaspar (EVP and COO)
Yeah, Neil, first question around the Wolfcamp B. I mean, this is, this is so important and fundamental to what we do around the assessment work. You know, talked about on several calls, this 10%-20% of the dollars that aren't directed towards the most near-term capitally efficient, but it's so important that we dig deeper out into the portfolio to de-risk these opportunities. When we see, you know, after several reps of really understanding what that opportunity is, and they certainly jump up to the front of the line, compete even with some of the best stuff we're investing in today, it's pretty exciting. So that's something we just wanted to share, specifically in Cotton Draw, specifically in these Wolfcamp B zones. These are really accretive, and very valuable.
Now, full disclosure, they're already baked into the inventory numbers that we guide to, but they're baked in on a risked standpoint. As we de-risk them, net-net to us, there's real value creation in being able to, to prosecute on those. The second question was around moving the opportunities forward. You know, we have 16 rigs running. They're all running just a little bit ahead of pace. The completion crews, same, same deal there. Four frack crews for the front half of the year in the Delaware Basin. They're just running just a little bit ahead of pace. That fourth crew that we toggle on and off originally was slated to run through October, then we pulled it back to September, then August.
We finally were able to release that in July and accomplish everything that we needed to accomplish. You can imagine the, the well cost savings and the value creation on a per-well basis. Now, it kind of monkeys with our quarterly numbers a little bit, as, as you can see, but overall, we're always trying to pull that value forward. We're thinking about per well, full cycle cost, how do we continue to drive that? Then how does it manifest to the bottom line of the company?
Neal Dingmann (Managing Director of Energy Research)
It makes sense, and maybe the last one for Jeff, just on capital allocation. Just for Jeff, how aggressively, Jeff, do you all think about going forward? Do you all plan to target net debt while combining this with your strong short-lived return program?
Jeff Ritenour (EVP and CFO)
Yeah, I appreciate the question. I think going forward, you're gonna see our, you know, as our, our framework's been pretty consistent from day one, as, as Rick mentioned in his, in his opening remarks. You, you shouldn't expect a material change in, in that approach. You know, we're gonna be pretty balanced. As you saw this year, year to date, between the variable dividend and the stock buyback, it's been about 50/50, which to me is a, a great example of how well our framework's working. Last year, when you had much higher prices and significant free cash flow generation, we leaned in on, on the variable dividends, and this year, when you've seen that pull back, you've seen much more balance from us with, with the stock buybacks as well.
Going forward, you know, where we are from a cash balance and a, you know, a framework standpoint, as we generate excess free cash flow here in the back half of the year, given the lower capital spend we expect and the higher oil prices that we're projecting in the back half of this year, we should generate significant free cash flow. We're going to look to build our cash balance back, and then with the remainder of the cash, we're gonna, we're gonna focus on obviously the variable and, and the stock buybacks on an opportunistic basis.
Neal Dingmann (Managing Director of Energy Research)
Very good. Thank you.
Operator (participant)
Thank you. Well, our next question comes from Doug Leggate from Bank of America. Doug, your line is now open.
Doug Leggate (Managing Director and Head of US Oil and Gas)
Guys, I've got two, if you don't mind. One is on mix, and one is on portfolio capital intensity, and I guess it's we've seen this trend, obviously, on across a number of your peers, but if we look at the oil mix in your production, it's obviously been up and down a little bit over the last couple of years, but seems to have dropped now below 50%. I'm just wondering, when you think about how you're allocating capital between your different operating areas, particularly, I guess, Anadarko versus Permian, how do you anticipate, as you optimize your spend, that that oil mix is going to trend? I've got a follow-up, please.
Jeff Ritenour (EVP and CFO)
Yeah, Doug, this is Jeff. I would say, you know, we view that, that the mix of the oil to be pretty consistent on a year-over-year basis. We're really focused on rate of return, and the returns that we generate in our play. We're agnostic, frankly, to, to oil or gas, but, but as we all know, certainly oil is the higher margin product today, and our focus has been particularly in the Delaware. With the, with the, with the Dow Inc. that we have in the Anadarko Basin, that obviously juices those returns and helps from a capital efficiency standpoint, and makes that activity pretty competitive with our broader portfolio.
I think we would, we would all tell you, and it's not gonna be a surprise to anybody on the call, that the Delaware, without doubt, is our most capital efficient asset today. It's oil-weighted. That's where the bulk of our margins come from, as we move forward into 2024 and beyond, we would expect it to capture the lion's share of our capital investment.
Doug Leggate (Managing Director and Head of US Oil and Gas)
Okay. I, I, I, I guess we'll take another look at that. My, my follow-up, Jeff, is, look, look, I realize that inflation and costs and everything else are, it's a well-trodden path. Everyone understands what's going on there, what has gone on there. But I wanna share an observation with you just to get your opinion on this and see what you think. When I look at your peers, obviously one of your large peers reported this morning, that the, the capital intensity, simplistically, on a per BOE basis, is up about 30%. Yours is up about 80%. For example, if I take your spend in the first half of last year, it was about $10 a BOE. First half of this year, it's about $17 a BOE, and production's obviously up small.
I'm just wondering if you can address that and tell us what you think is going on. Is there capital in there that is transitory, for example, in the infrastructure you talked about? What, what else should we be looking at to try and understand what's, what's changed there?
Jeff Ritenour (EVP and CFO)
Yeah, Doug, I would say, as you know, it's a mix of things. Without a doubt, one of the things that we've talked about a lot is the inflation that's hit us, and certainly started in the back half of last year and worked its way into this year. That's a big driver of that. The timing of our contract tracks and the roll-off of our contract structure as it relates to all the different cost categories, I think has also disproportionately hit us relative to our peers. Said another way, I thought our teams did a great job of protecting us from the inflation in the, in the very early part of the cycle.
Think about the fall of last year and the early part of this year, and now as we've worked our way through 2023, a lot of those contracts have rolled off into a higher price environment from an inflation standpoint. You've seen some of the capital efficiency for our asset base relative to some others, certainly change. Obviously, mix is a big driver of that. The shift that we made with the acquisitions in Validus and RimRock, you're moving away from a more capital efficient asset in the Delaware from a mix standpoint, to really great assets, really great returns in the Bakken and the Eagle Ford. As I mentioned in my, my, my response to the previous question, they're certainly not as capital efficient as what we, what we see in the Delaware.
You put all that together, and I think that's what you're seeing really driving that capital efficiency rate of change relative to some of our peers. I, I will say, though, when you step back and you look at that capital efficiency on an absolute basis, you know, company versus company, we feel really good about where we sit, and we look really, really competitive against the top-tier companies in the space. That rate of change, as you point out, has just been pretty material, and have been a challenge, you know, on a relative basis as you all screen for capital efficiency.
When we look, look at the capital efficiency on an absolute basis, we still feel really good about where we sit, and we expect that to improve as we work our way into the future, for all the reasons you mentioned earlier, which is we do expect to see some deflation, as we work our way through the back half of this year and the next year. As Clay mentioned earlier, the mix of our asset base and the things we're focused on, we think that only is gonna add to our productivity moving forward.
Doug Leggate (Managing Director and Head of US Oil and Gas)
Okay, thanks for the answer, Jeff. Appreciate it.
Operator (participant)
Thank you. Well, our next question comes from Matthew Portillo from TPH&Co.. Matthew, your line is now open.
Matthew Portillo (Partner and the Head of Research)
Good morning, all. Clay, maybe a question for you to start off on the Bakken. I know that's an asset that has faced some technical challenges to start the year. Could you unpack some of the headwinds a bit more that you faced in the first half, and maybe a little bit more around the completion design change that you guys have made, that may start to show some improvement in the well results in the back half, and heading into 2024?
Clay Gaspar (EVP and COO)
Happy to do it, Matt. Thanks for the question. You know, as I think about the Williston, it is certainly the, maybe the most mature of all the oil resource plays. We're learning things for the first time, what these late innings really look like. Certainly with the RimRock acquisition, bringing those wells in, we've faced some challenges really from a subsurface standpoint, but also some, from a relatively surface standpoint, and I'll talk about both. From a subsurface standpoint, one of the challenges we faced, specifically with some of the wells we acquired, is the nature of the depletion. These cross-cut wells are really unique, and so we've seen wells we've drilled through essentially have a depletion, and then essentially virgin pressure, then back to depletion throughout the, the lateral.
Producing those, completing those and producing those have been a relatively unique challenge we haven't seen anywhere else. We've gotten some solution I've talked about earlier. I think we're doing really well on getting those wells, producing consistently, getting them unloaded, allowing the proppant to stay in, stay in place, which is fundamentally important to be able to producing the wells. More on the surface side, once you get that, that proppant in place, then you don't have the challenges of artificial lifts. You don't have the sand flowing back to surface and adding additional complications. What we really faced in the first quarter was some of these operational challenges, and then still in a very tight.
Workover rig environment, reaching for that workover rig, having to stand in line, or, the opportunity cost of pulling it off of something else we were trying to do, has been pretty uniquely challenging. I think we've gotten a good recipe for the wells going forward. A lot of our inventory that we're able to go back to now will not have some of these same challenges. It's more run-of-the-mill, what we've been dealing with in Williston for the last several years, and really delivering some really good well results. Yes, the first quarter was challenging from an operational standpoint, especially in the first quarter, compounded by weather. I feel good about the direction we're headed, the response we've had from the team, and the outlook going forward.
Matthew Portillo (Partner and the Head of Research)
Perfect. Then just as a follow-up, in your prepared remarks, you mentioned seeing quite a bit of success in the Anadarko Basin and the potential for a further expansion of the partnership. Just curious, is, is that something that you may pursue with Dow, or are you looking at bringing in potentially other partners to continue to progress the asset from a development standpoint?
Clay Gaspar (EVP and COO)
You know, we cherish our partnerships, and we love it when it's a mutual win-win. Dow's been very pleased with this partnership. We have as well. It's allowed the Anadarko Basin to compete in our pretty rigorous portfolio, and so expanding that, you know, certainly Dow has a very good knowledge of the basin. It would be the easiest to pursue with them. You know, certainly, look, we're, we're objective. We have other partnerships around the company, but, you know, it's something we're regularly talking about with Dow. How would this work for them? How would this work for us? We haven't made any decisions on that, just thought I would mention, we have an additional runway beyond the current scope that we may end up pursuing at some point.
Matthew Portillo (Partner and the Head of Research)
Thank you.
Operator (participant)
Thank you, Matthew. With our next question comes from Scott Hanold from RBC. Scott, your line is now open.
Scott Hanold (Managing Director and Senior Energy Analyst)
Yeah, thanks. I'm just wondering if, if, you know, you, you've have some thoughts on, on just the overall maturation and, and depth of your inventory. It, you know, appears, you know, with, with you all, that there's, you know, a little bit more exploration and, and, you know, refrac and other kind of opportunity. Does that point to the, the maturity of some of the assets? And, you know, is there a little reason more to do more kind of exploration and development of that sort? Or just give us a sense of, like, when you think about, like, primary drilling of economics you have today, like, how, how much of a runway do you have?
Rick Muncrief (President and CEO)
Hey, Scott, it's Rick. We, we feel really good about our runway, but we also are compelled to to continue to explore, to continue to assess what we already own. You've heard some several comments, commentary around consolidation opportunities. I think it's incumbent upon this management team to first, let's understand what the opportunities we already have in, in hand. You've heard Clay talk about how we had in the Wolfcamp B, we feel really, really good about some resource potential there. We had it in a, in a risked basis, and you go out, and you execute on those, and you find out that they really are good.
The implication is that not only the offsets of where we're at, but when you think, think about a 400,000-acre position that we possess in the Delaware, and you can continue to do these these assessment, the activities, and quite honestly, you either meet or exceed what your expectations are, that's a good thing. That's better than good. That's a great thing because that adds to, to your your risk, or your unrisked, or excuse me, your risked inventory that you feel really good. When I say that, that's inventory you're pulling off the shelf and executing on and with phenomenal returns.
So whether it's, whether it's in the Delaware, whether it's these, these opportunities we have in the Eagle Ford, which we're really bullish on, which it's, the opportunities we see in, in the Bakken, which we continue to see, some, some nice opportunities there, you know, we, we feel really good about it. I think it's in, it's incumbent upon this team to continue to assess what our current, acreage position is as we compare and contrast, executing on that, holding what we have, versus, going out and, and buying more, consolidating more. Just, it's real fundamental to our business.
Scott Hanold (Managing Director and Senior Energy Analyst)
Yeah, I mean, and that's good to hear, and I, and I think the question is, is a lot on sort of the capital efficiency trend as, you know, you move, you know, from a, a very high core, you know, prolific Delaware Basin to, you know, some of these other zones or even to some of these other, you know, plays like, you know, the Anadarko and Eagle Ford and, and Williston or PRB, right? It's, it's more about that capital efficiency trend relative to kind of the best stuff you've already drilled.
Rick Muncrief (President and CEO)
Right. I think that's what you're gonna see. I think, you're seeing maturation in, in a lot of these basins. If you just think about, whether it's you, you've seen it in the Midland Basin. We're not in the Midland Basin, but you've seen that for several years, where, you know, every year, until you start bringing new resource on, you're gonna be continuing to evolve, and people tend to go to their highest, returns. What, you know, we've seen it in the Bakken, we've seen it in the Eagle Ford. I, I can tell you, there's many of these basins, we're excited about the, the potential that we see with, restimulation and, and, some tighter spacing. In some cases, we up space in other areas. We just learn more about the resources we have.
That's been the history of our business over the last 100 years, is, plays and basins will mature over time until there's either a change in technology, you know, new intervals are found. I think you're just, you're seeing that play out in real-time. We're continuing to we're excited about what we're, we're seeing. Hopefully that's coming across, you know, in our, not only our prepared remarks, but some of our answers that whether it's re-stimulation down in, in the Eagle Ford, whether it's what we're seeing assessment work in the Delaware, and, and other, other place, Powder, Anadarko, we're just real excited about what we have.
Scott Hanold (Managing Director and Senior Energy Analyst)
Okay. No, I appreciate the added color. Just one quickly on, on the, the fixed dividend. You, you spent a little time, Jeff, on, on buybacks and, and variables, but remind us of your thoughts on, you know, the fixed dividend, where you want that to be? You know, I think it's about a 1.5% or something to that effect. Do, do you feel good about that, or would you like to see it, you know, stronger relative to the S&P or, or to some of your, obviously, E&P peers?
Jeff Ritenour (EVP and CFO)
Yeah, no, absolutely. I'm, I'm glad you asked the question. We're, we're absolutely focused on growing the fixed dividend as we work into the future, and so you should expect us on a, on a year-over-year basis, to, to, to lean in and, and grow the fixed dividend as, as we, we get more and more confident, obviously, in our base game plan and, and our, and our, our framework. It's, it's. Yeah, I certainly should have mentioned it earlier. It's, it's the priority one as it relates to our cash return framework, and it only falls behind, obviously, the, the financial strength and the, and the, and the balance sheet. Absolutely expect to see us grow that into the future.
Scott Hanold (Managing Director and Senior Energy Analyst)
Thanks.
Operator (participant)
Thank you, Scott. With our next question comes from Paul Cheng, from Scotiabank. Paul, your line is now open.
Paul Cheng (Managing Director)
Thank you. Good morning. Two questions, please. First, I think, Clay, you mentioned that Bakken is the most mature, which is certainly the case. You talk about the refrac and the development opportunity in Eagle Ford. Can you talk about within your portfolio, have you already looked at what is the refrac and the development opportunity in Bakken and Outlar? Do you think you may be able to hold the current production spread? The second question, going back into the Eagle Ford, I know you're still early, but for refrac and the development, what kind of WTI and Henry Hub gas price minimum you need in order for those to work? Thank you.
Clay Gaspar (EVP and COO)
Yeah, I'll, I'll tackle those, starting with the Williston. You know, it's a very different reservoir rock than the Eagle Ford. The Eagle Ford is very- it's notoriously tight, low permeability, which is a challenge in trying to initially develop. What we're finding is there's some benefits in redevelopment, being able to space in wells later in life and not having some of the challenges that we see in, in other basins. We're not gonna be able to do that same kind of model in, in many other basins because it's fairly unique to the Eagle Ford. When it comes to refracs, it's a little bit different scenario. Williston being on the more mature end and also having a fair amount of the development early in the industry's understanding of how best to complete these wells, there's some really inferior completions.
So the opportunity there is a little bit different. It's not from a reservoir standpoint, it's more from a completion standpoint. How do we go in and re-stimulate some of these wells that were massively under-stimulated? Therein lies a different opportunity there. The Eagle Ford, you asked about kind of break-even costs for the refracs. I, I don't have a very good number for that. I would say in the top half of the opportunities that we're looking at, many of those are very competitive with what we're drilling today, which is pretty a very, very solid return. I would put it in that bucket.
There's still a lot of work to do on refining how do we figure out, where is the line, and certainly commodity price will play a role in how many of these refracs, and then potentially even tri-fracs, you come back again, at a later date. Those opportunities will certainly be commodity price, dependent.
Rick Muncrief (President and CEO)
You know, Paul, it's Rick. I, I'd just say that when I think about those re-stim opportunities down in the Eagle Ford, in my, in my mind, you know, in a $50 world, as long as you're north of $50 and a $3 Henry Hub, you're gonna have some pretty, pretty, pretty good returns. We're, we're pleased with that. You know, one of the things I'll add, the previous question we had, we had was around some of the assessment work. Just everybody needs to recall, we're only doing a small percentage of our capital budget with, with, with assessment work. It's not like we're really leaning in on that.
We do think it's important to, to allocate a certain amount of capital and, really excited about what, what the, what it holds for us. That being said, I know at a time when, when people are, are, are hyper-focused on, on capital efficiency, that's fair. It really is. We also need to think about the future. When I say the future, it's not next quarter. You know, it's, it's the next five, 10, 15, 20 years.
Paul Cheng (Managing Director)
Thank you.
Rick Muncrief (President and CEO)
All right. It looks like we're at the top of the hour. I appreciate everyone's interest in Devon today, and if you have any further questions, please don't hesitate to reach out to the investor relations team at any time. Have a good day, everyone.
Operator (participant)
Thank you. Ladies and gentlemen, this concludes today's call. Thank you for joining. You may now disconnect your lines.
