Diamondback Energy Inc (FANG) — Q4 2022 Earnings Call Transcript

Thank you, Eric. Good morning, and welcome to Diamondback Energy's fourth quarter 2022 conference call. During our call today, we will reference an updated investor presentation, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO; Kaes Van't Hof, President and CFO; and Danny Wesson, COO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. Reconciliation of the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's fourth quarter earnings call. 2022 was another great year for Diamondback. We successfully executed on our capital program, accelerated our return of capital plan, and generated record cash flow. I'm very proud of all that we were able to accomplish and look forward to what I believe will be another strong year for the company. Looking back at last year, we produced over 223,000 barrels of oil per day, exceeding our production expectations. This is primarily the result of our well performance, which continues to trend in the right direction as our normalized oil production in the Midland Basin improved by 6% year-over-year and nearly 20% when compared to 2020. We continue to optimize our multi-zone co-development strategy, which we pivoted to prior to the pandemic by tweaking our frac designs, spacing assumptions, and landing zones to maximize our returns. On the operations side, we've also built out substantial water infrastructure, which allows us to implement simul-frac completions across our position. This type of completion is consistently more efficient than a traditional zipper frac design because we can complete approximately 80 wells per year with just one crew. When you add in the additional efficiencies we're seeing from our Halliburton e-fleet, our completion savings are approximately $50 a foot. Last year was not without its challenges from significant inflationary pressures, particularly with casing, equipment availability, and weather-related downtime. However, our operational team did what it always does, deliver best-in-class execution. Our ability to hold our capital budget flat and stay within our original guidance range while also exceeding our production target is something you should expect from Diamondback as we push to deliver differentiated results quarter after quarter. Financially, we generated over $7 billion in EBITDA and $4.6 billion in free cash flow or nearly $26 per share, both records for the company. We made significant progress on our return of capital plan, increasing our cash return commitment in the middle of the year to return at least 75% of free cash flow to stockholders. In total, we returned 68% of our free cash flow in 2022, which equates to $3.1 billion through a combination of our base and variable dividend and share repurchase program, buying back nearly 8.7 million shares at an average price of $126 per share for a total of $1.1 billion. This represents 5% of our shares outstanding when we announced our program in September of 2021. An additional $2 billion was returned through our base and variable dividend with the total dividend growth of nearly 5x when compared to 2021. In total, we returned $11.31 per share in dividends. In the fourth quarter alone, we returned over $860 million or $5.65 per share with a total dividend yield of nearly 9%. This included an increase to our annual base dividend of $0.20, now $3.20 per share annually or $0.80 per quarter, representing 54% year-over-year growth. We also announced multiple strategic transactions in the fourth quarter that better position us for the long term. We made two Midland Basin acquisitions, Lario and FireBird, both of which are now closed and seamlessly integrated that added over 500 high-quality opportunities and 83,000 net acres to our portfolio. This additional inventory, along with the associated production and cash flow, has solidified our size and scale in the Midland Basin, giving us a strategic advantage as we execute on our capital programs for the decades to come. Last summer, we bought in all the outstanding units of Rattler, which gives us additional flexibility to think strategically about our existing midstream portfolio. We now have the ability to monetize assets that trade at a higher multiple than our upstream business and use the proceeds to strengthen our balance sheet or acquire additional upstream assets. The first example of this was the sale of our 10% interest in the Gray Oak crude oil pipeline to Enbridge. We achieved a 1.75 multiple on our invested capital and used the proceeds to partially fund the cash portion of the Lario acquisition. As we evaluated both our Rattler operated assets and equity method investments, we've also monetized multiple noncore upstream positions. We have now divested nearly $600 million in upstream assets since the third quarter of last year, which includes two recent deals in Southeast Glasscock and Ward and Winkler counties. These assets simply did not compete for immediate capital within our portfolio. We have now increased our noncore asset target sales from $500 million to at least $1 billion by the end of this year. Last year, we improved our leverage ratio, now below 1x, and also pushed the tenor of nearly 90% of our debt past 5 years, with over $2 billion due in 2050 at an average coupon of below 5%. We will continue to use free cash flow and proceeds from our noncore asset sales to lower our overall debt profile, continually improving our financial position. As we move into 2023, we expect to deliver relatively flat pro forma production year-over-year. When you account for the 11 months of Lario and a full year of FireBird production contribution, our guidance reflects 260,000 barrels of oil a day and $2.6 billion in CapEx, while running 15 rigs and 4 simul-frac crews. In closing, 2022 was an outstanding year for the company. We generated record free cash flow and distributed nearly 70% of it to our shareholders, strengthened our balance sheet, extended our inventory runway, and continue to produce one of the highest margin barrels in the industry. Looking ahead, our business model is working, and we are confident in our 2023 outlook and our ongoing ability to continue generating peer-leading returns for our stockholders. With these comments now complete, operator, please open the line for questions.

Thanks for all the details, Travis. My first question is about the topic of shareholder return. It's been almost two years since you first mentioned that once the macro supply-demand was more balanced, you might consider more growth. I'm curious if your thinking has changed based on what we currently know about ongoing investor shareholder returns or other factors influencing the environment today.

Yes, Neal, I don't think the current macro conditions are influencing any production growth. There's still uncertainty with the Federal Reserve's actions, uncertainty regarding the recovery of demand in China due to COVID, and Russian barrels are still making their way into the market. It seems to me that the macro conditions have not fundamentally changed. Additionally, the feedback we receive from our shareholders encourages us to continue prioritizing higher returns for them.

Yes. I think also on top of that, Neal, we're going to be growing oil production per share significantly in 2023 through two well-timed acquisitions and a significant amount of buybacks in 2022. So per share metrics continue to improve. We continue to invest in high-return projects while not having to change our activity plan on a monthly basis trying to follow the crude price. The plan is the plan, and this steady state of activity has produced good results to date and no need to change that while it's working right now.

Good point, Kaes. That might lead me to inquire about capital efficiency. Specifically, based on our calculations, you generate more free cash flow per barrel of oil than any exploration and production company. I'm curious whether this is primarily due to the co-development you mentioned or if it's related to capital efficiency. Recently, you seem to be achieving impressive results, and I'm interested in what you or Travis might identify as the key drivers behind this important metric.

Yes, it's certainly not just one thing, Neal. It's really a combination of various factors that we focus on multiple times a day when executing our program. Productivity enhancements contribute to this, but it's really a result of a tough decision we made in 2019 to pivot away from the best two-zone development strategy and adopt the multi-zone full section development strategy, which is yielding benefits today. We also frequently discuss our cost structure, which consists not only of expenses—such as general and administrative expenses or lease operating expenses—but also includes capital efficiency, where we continue to push the boundaries, particularly on the variable cost side, by simply doing more with less. All of these factors combined consistently position us among the most margin-efficient producers in the basin.

The first question I had was around noncore asset sales and you did bump your target from $0.5 billion to $1 billion by year-end 2023. Can you give us a little bit more color around what are the natural strategic assets? And what the market looks like for asset sales right now?

Yes, Neil, great question. I think we announced two E&P asset sales, noncore asset sales this quarter that I think fit the mold of what the market looks like right now. And that's assets that don't compete for capital in our capital plan for many, many years and a little bit of PDP associated with those assets. But generally, a buyer that is looking to develop those assets a lot faster than we're planning. And so these two deals, the buyers are going to get aggressive developing these two assets right away, which in the capital allocators, it's just good capital allocation from our perspective. Going into it, we expected to sell more midstream assets than E&P assets. So that's why we bumped the target, and we still have some strategic midstream investments that are nearing the point where they should be monetized. Gray Oak, I think, was a great example. We retained all of our commercial benefits of the transaction. We still move our barrels to the Gulf Coast. But just from a financial perspective, the pipeline was a great investment and it worked, and we monetize it to the partners. So I'd expect more on the midstream side. We did highlight what we have from a midstream perspective in the deck for the first time, but we're going to be patient and prudent when it comes to selling assets.

Yes, that's great perspective. And then the follow-up is the oil volume guide for the full year was solid. Q1 a little bit softer. So maybe you could just talk about the cadence of production over the course of the year and just how we should be thinking about the path for oil production in particular in 2023?

Yes, that's a good question. When we acquired Firebird, it was producing 17,000 barrels of oil a day. We expected that asset to produce 19,000 barrels a day for 2023. We are already seeing some growth from that asset, with the majority of the benefits expected in Q2 to Q4. Additionally, with the closing of the Lario acquisition on January 31, we have a reduction of 6,000 net barrels a day from Q1 because we couldn't count those volumes in January. Our plan is to grow steadily from Q1 through Q4, and we have the projects to support that growth.

Travis, you mentioned in your prepared remarks how the company has really optimized its multi-zone co-development strategy over the last couple of years. I was wondering if you could provide a little bit more detail around what you're doing today? I know, on Slide 16, you gave us a lot of great detail on the amount of net lateral footage by zone, but I wanted to understand what you're doing to maybe mitigate some of the issues we're seeing from the industry in terms of parent-child interference and impact some delayed targets. And just your thoughts on sustaining the level of well productivity gains that you generated last year into the future.

Yes, that's a great question, Arun. In 2018 and early 2019, we closely examined our co-development strategy, and we found that all these zones interact with each other. This interaction means there is pressure communication during the fracking operations, which leads to shared reserves between individual wells. If we don't adequately address this during the initial development, we find that those zones have some depletion when we return later, and this depletion can reduce the efficiency of the stimulated rock volume, ultimately affecting the production profile. To tackle this, we reviewed our spacing assumptions both laterally and vertically and made adjustments to minimize fracking pressure interference. We spread some zones further apart and adjusted their positioning, which led us to focus on half of a section for our development strategy, completing all the wells simultaneously and bringing them online together. This was a challenging decision, as it's often easier to drill the best zone, but we learned that this was not the most effective approach. We took valuable lessons from this in 2019. As shown on Slide 16, our well results in the Midland Basin are on par with what we experienced in 2017. I'm very proud of our technical team's hard work in solving a complex issue and their commitment to this strategy, even during challenging periods when we faced skepticism. I hope that answers your question, Arun.

That's helpful. And maybe just a follow-up. I wanted to get some thoughts on some of the initial well results from FireBird. I believe in that transaction, you guys underwrote just over 350 gross locations, but you highlighted some potential upside based on co-development opportunities. I was wondering thoughts on maybe some of the initial results in the Wolfcamp A, which I don't think was part of your original assessment of locations that you paid for.

Yes, that's a great question, Arun. FireBird really represents an ideal Diamondback opportunity, as we are very familiar with the area and have been in close communication with the FireBird team as they explored their position further west in the basin than previous attempts. We have been monitoring the results closely and recently shared a few that seem to affirm our analysis while also indicating potential for upside in the central prospect. There are a couple of wells, and the outlook may change on the far west side. This was likely the furthest west test so far, not an area we initially evaluated, yet it produced a strong result in the Wolfcamp A formation. Additionally, in the southern part of their position, we have the four corners two-well results in Wolfcamp A and Lower Spraberry. We had originally assessed Lower Spraberry with a belief in Wolfcamp A potential in the central prospect, and it appears that co-development of Lower Spraberry with Wolfcamp A may be feasible across that area. It’s still early days, but definitely a positive indication from the FireBird deal and our technical team's efforts in successfully concluding that transaction.

The first question is really just a follow-up on Arun's question. You've seen a thematic of your peers testing additional zones this year. Maybe can you give us a sense of the 330 to 350 wells you're doing this year? current inventory?

Yes, David, you're breaking up a little bit there. So I'm going to try to repeat what I thought you said, which is, what other zones are we testing outside of our traditional development zones across the basin. Is that correct?

That's correct. Sorry about that.

Yes, no problem. So generally, right, the majority of our capital is going to be allocated to the best zones, co-development. A big development this year in kind of the sale of Robertson Ranches and the Central Martin County area. So that's where the majority of capital is getting deployed. Certainly, there are deeper tests going on throughout the basin. We have our Limelight Prospect, which covers those deeper zones, a tariff structure on the eastern side of the Midland Basin, where we're going to be developing some Woodford and Barnett. Generally, we're probably going to drill 3 or 4 wells there this year. I don't think it's going to be 10, 15 plus, but I think generally, promising results from the deeper zones across the basin and the benefit of our position is that we hold a lot of those deeper zones, and we have a significantly large mineral company that owns mineral rights to the center of the earth forever in all those zones. So if those zones start getting leased up, it's a great benefit to the Diamondback-FireBird relationship.

And then third year now of being in relatively a maintenance mode or low-growth mode, have you seen noticeable differences year-over-year in benefits from perhaps improved base declines? And how does decline work on '22 or '21?

Yes, again, breaking up a little bit, but talking about base declines. I think the base business, obviously, the base decline continued to decrease since being in maintenance mode from 2020. We did add two acquisitions in FireBird and Lario, where they have built a lot of rate very quickly. And so those two deals have a higher decline rate than the base business, but I think we've managed that in our guidance and also manage that in how we're going to complete wells across the pro forma position. So certainly, base decline is coming down, but I really think the best benefit of this lower growth environment is that we can grow per share metrics while not having to change our development plan with every $10 move in oil price, right? The plan is the plan right now. Shale has certainly become longer cycle with these bigger pads. And so we're not having to put a stress on the ops teams to move pads around if oil moves $5 or $10 a barrel.

Our first question maybe just following up on David's question there on capital efficiency. Capital efficiency looked great in Q4, and you turned to sales about 55 net wells and you hit oil when your guidance, we think, implied like 73 net wells, so that's great. For 2023, the number of wells to sales looks a little bit higher than what we would have expected, if we just use the amount of wells you did in '22 and then we add in the Lario and the FireBird deal wells. So are we looking at that math correctly for 2023? And any color you would have would be helpful since including the divestitures, we still think the '23 outlook looks conservative, and we're assuming that the priority is really to beat on CapEx and not volumes.

Yes, Jeanine, I think a couple of things. Q4 was shaping up to be a strong quarter as we approached December. We experienced a winter storm that affected our production, although Diamondback did not disclose the impact of the storm. As we entered the last 10 days of the quarter, we were confident about our position and still managed to meet our guidance. Consequently, we decided to transfer some wells from Q4 to Q1 to get a head start on first production. This shift does not significantly affect our capital, but it does influence our projections for initial production. Therefore, there will be a good number of initial productions in Q1 2023, as we were ahead of schedule in Q4 and optimistic about our start in Q1 this year.

Okay. Great. And then maybe just going back to return of capital. Looking at just the buyback plus the variable amount for this quarter, the buyback was about 44% between the two of those. Is that rough split kind of indicative of what we should be expecting in the future? Or is it really just more opportunistic every quarter? We're just checking in if there's any change in how you're viewing the variable versus the buyback.

Yes, no change, Jeanine. Really, the variable is the output of how many shares we didn't buy back in a particular quarter, and the buyback is still going to be very opportunistic. And I think now that we've kind of gone through this for four or five quarters, you can see that we step in and buy back when things are weaker. There's still been a lot of volatility in the space. We're going through a period of that volatility right now. And so you look back at a quarter like Q4, bought back less shares in October and November, but hit the buyback very hard in December. And I think you can expect us to keep doing that and then having the variable be the output of what base dividend plus buyback doesn't get through in a particular quarter.

Good morning, all. Congrats on a strong year-end.

Thank you, Derrick.

Thanks, Derrick.

Building on an earlier question, I wanted to focus on your well productivity. Aside from the development sequencing impacts, are there one to two primary drivers that would explain the improvement you observed in well performance year-over-year?

I believe the primary advantage, Derrick, is not only the assets we acquired from QEP but also the guidance we provided. That deal, completed during a challenging period, perfectly aligned with our transaction objectives. We are now channeling more capital into these assets than we would have into the business before the acquisitions, which is yielding some benefits. These assets are located in regions suitable for multi-zone development, allowing us to develop large pads in high-return areas and benefit the Viper side with strong mineral interests. As Travis noted earlier in the call, we are closely examining spacing, learning from other operators in the region, understanding best practices, and rapidly applying those insights into our strategy, which is proving to be beneficial.

Perfect. And for my follow-up, I wanted to focus on your 2023 capital program. If we were to assume a flat commodity price environment, where are your greatest headwinds and tailwinds from a service cost perspective?

The biggest headwind over the last six quarters has been casing costs. Now we can certainly see around the corner that maybe we're seeing some softening there. I'm not going to count on it until we see it, but casing has moved up from, let's call it, $40 or $50 a foot to $110 a foot. It's 20% of our Midland Basin well cost now, and that's a significant headwind over the last six quarters. I think the headwind is going to ease. If not, it's a little bit out of our control. But the things that we can control are the efficiencies gained from simul-frac operations. We'll probably have four simul-frac crews running by Q2 of this year, which is highly efficient, saves about $30 a foot versus conventional crews. And on top of that, two of those crews are going to be the Halliburton e-fleet Zeus crews, and those use less fuel but also run on cheap Waha gas right now. So that saves another $15 or $20 a foot. So we're doing what we can to cut costs and keep costs as low as possible in an inflationary environment.

I would like to discuss the gas takeaway situation and your positioning regarding Waha basis risk. What is your approach to flow assurance this year, and if possible, next year?

Good question, Roger. I don't think flow assurance is going to be an issue for us, but we are exposed to the Waha price based on how the contracts are written. Through the history of Diamondback, we've been very acquisitive, and when we acquire things, it comes with contracts. And so, all those contracts are with private equity-backed or some of the public gatherers and processors in the basin. So I feel really good about our flow assurance and our contracts, the issue is going to be price. And what we've seen in the basin is some tightness coming out of the basin on Waha when pipelines have gone up or gone down over the last six months. But really, there's a lot of processing capacity that's now coming on in the early part of 2023, particularly with two of our Midland Basin gatherers and processors. And I think that generally is going to move the issue further downstream. So it's going to be a tight gas market in the Permian. Henry Hub prices obviously aren't helping as well, but we feel good that the gas will move, and we're well hedged financially to protect from that downside.

Thank you for that. I would like to revisit the question regarding Page 23 of the hedge summary. What are your thoughts on the hedging strategy for Q1 and Q2? Would you want to maintain a similar approach for the second half of the year as we get closer, especially since it may become more financially viable? Or, given the current structure of the balance sheet and the cash inflow expected from upcoming dispositions, are you more inclined to reduce the level of hedging?

Great question, Roger. We don't believe in no hedges, I think, primarily because our balance sheet is a hedge. Our cost structures are hedged, but we consider our base dividend debt, right? And our base dividend is now $3.20 a share. It's almost $550 million of outflows a year. We think it's well protected today at $40 a barrel, but we don’t want to put that in harm's way. So we buy puts as fire insurance, and we basically use the front quarter to extend duration three or four quarters out. We try to be 50% to 60% hedged going into a particular quarter on oil, down to 0% hedge four, five quarters out. So I think you can continue to expect us to do that, and your observations are 100% correct that in the back half of the year, it will grow as we go through the year.

Just a couple for me, follow-ups on the service cost environment and Diamondback read-through specifically. I guess, first, I appreciate the comments on what you're watching for and how Diamondback is positioned to really maximize what you all can control. But I wonder if you could speak a little more broadly to what you're expecting in terms of year-over-year changes on inflation. I think the materials speak to 15% as the base case and really more so how that compares to what you're seeing on a leading-edge basis? And then I guess the last one is, how we should think about the balance of the CapEx guide for this year in that context? And then the second part of my question is, just looking for a snapshot of well cost today on a per foot basis are tracking relative to the full year guide range and also relative to the mid-November snapshot that we got in last quarter's earnings?

Good question, Jeoff. Generally, we anticipated this year to have around a 15% increase in well costs year-over-year, which is less than 10% compared to what we discussed in November. Those numbers still hold true today. We're likely in the upper half of our well cost guidance for both Midland and Delaware. Additionally, we're seeing some developments beyond just service cost deflation. For instance, Halliburton's Zeus e-fleet is moving to four simul-fracs compared to last year's three in a spot crew, which adds efficiency. I see this budget in two ways this year: if we experience deflation, we may be closer to the lower half of our guidance, while if costs remain flat, we could be at the midpoint to the higher end. Overall, it appears that some favorable trends in service costs are emerging, and unlike last year, not every aspect will see an increase in the AFE.

I want to circle back on the completion efficiency comments. E-frac obviously brings a pretty good fuel savings given the gas diesel spread here and obviously, associated ESG benefits. But do you think e-frac additions will be additive to the improvement in cycle times above and beyond what you're seeing from simul-frac?

I think, generally, Scott, they complete a similar amount of lateral feet as the simul-frac crews as we're seeing early time. But on top of that, e-fleets on a fuel efficiency basis, not just the type of fuel, but the efficiency of the fuel used has been a positive surprise. I think the last thing I would add is that it does operate on a much smaller footprint. So maybe your moves are smaller, but you do have some electrical infrastructure associated with those fleets. Dan, do you want to add anything on that?

Yes. I think we've only been running the first crew for about six months, and we've been really impressed with the performance thus far. It's outperformed our other fleets kind of on the margin, but not too measurable. We do believe that over time, you'll see that gap widen in performance, just really believe that the maintenance required around the e-fleet equipment will be substantially less. So we're excited to learn through that with Halliburton and recognize some added efficiencies on top of just fuel savings as we go forward.

And if service costs do start to slip in the Permian with Haynesville rigs and frac crews coming out migrating over, how quickly do you think that will hit your D&C costs? If that starts to pivot here in the near future, is there an ability for you to realize that in the second half? Or we really talk about the 2024 benefit just given your contracts kind of in place at this juncture?

Yes. I mean, we don't really have any long-term contracts in place. We kind of have shorter cycle pricing agreements. I think generally, we're exposed to market pricing across the board, and we certainly have some protections in place on some of our consumables, but if we start seeing the market soften, which we feel like is a pretty good likelihood with where we see gas prices today, that should trickle down into the oil basins, particularly on the drilling services side of things first. And we've certainly not seen a lot of upward pressure on pricing in the first part of this year. It's been pretty quiet, and hopefully, we'll start seeing some help on the inflation front here through the second and third quarter.

Congratulations on the great free cash flow quarter. It looks like cash taxes came in well under expectations and the guidance for 2023 cash taxes was below our model. I wonder if you can talk about what is driving the cash taxes lower, and any benefits you may be receiving from acquisitions?

Yes. Good question, Kevin. The biggest benefit we did receive in the fourth quarter. Obviously, commodity prices came down quarter-over-quarter, Q3 to Q4. So that was a surprise for the positive on cash taxes. I guess that hurts you overall. But the biggest deferral we got was when we closed the FireBird deal came with about $100 million of midstream assets and some other fixed assets that we're able to depreciate right away, and so that allowed us to defer more taxes into 2023. As we've modeled 2023, we still have about $1 billion of NOL that will be exhausted this year. But on top of that, also closing the FireBird or the Lario transaction, which added some midstream and fixed assets as well. So generally, this is kind of our last year before being a full cash taxpayer. About two well-timed deals allowed us to push out a little more cash. Obviously, it's not the reason why we do the deals, but it's a nice tangential benefit.

I was hoping you could talk a little bit about LOE trends. Just looking at the guide here. In '23, you guys are expecting LOE to come up a little bit kind of versus where it was in '22? Maybe just a little color around what you're sort of seeing there.

Yes. I think there are a couple of factors affecting our lease operating expenses. First, we are quite exposed to the power market, and we went through the latter half of last year with minimal hedging. As a result, the increase in gas prices significantly affected our real-time power pricing, which has remained somewhat elevated in the early part of 2023. We are trying to predict where we will end up regarding power and explore opportunities to hedge ourselves for protection, which is currently adding about ten cents. Additionally, the FireBird acquisition, which included around 900 vertical wells, has contributed another ten to twenty cents to our consolidated lease operating expenses. When you consider these two factors, we are looking at approximately twenty-five cents, and we believe we are likely operating at the lower end of our guidance today. If some favorable conditions arise, there's potential for us to be below our guidance, but we are not factoring that into our projections.

Okay. Appreciate that. And then just on M&A, obviously, you guys were helpful in terms of talking about some of these noncore asset sales, but I think you did mention in your prepared comments that perhaps some of those proceeds could go to bolt-ons out there in the space. I was hoping you guys could just give us a little color in terms of what you're seeing? Are there bolt-ons available that are kind of in and around your asset base? And how would you kind of characterize the market now? Do you think that generally speaking, expectations from sellers are reasonable these days? Just trying to get a sense of whether or not there's a decent chance you might pick something up here in '23?

Yes. I don't know if sellers are ever reasonable, Leo. But generally, I do think the two larger transactions did happen because Diamondback's cost structure was differential in the second half of the year and going into 2023, right? We're drilling wells $2 million, $3 million, $4 million cheaper in the Midland Basin than peers, and that is when you underwrite PUDs, that drives value to the good guys even if you're not running strip oil pricing. So I think generally, that's what's happened. There's less and less large opportunities like the two that we announced last fall. So it's relatively quiet at the moment. But some of the smaller things that tend to trend with the large deals like the blocking and tackling, a couple of other deals that Firebird and Lario we're working on when they sold. That's the kind of stuff that we're focused on right now.

In your presentation, you mentioned several energy ownership opportunities that are in the pipeline and gas processing. I'm curious if any of these are considered strategically important enough for you to take equity ownership. Also, regarding your inventory backlog, for those wells considered over 10,000 feet in lateral length, you mentioned roughly 5,500. Can you provide more details on what percentage of those wells you could potentially drill to maybe 3 miles? Additionally, is there a possibility for trades or swaps that could enhance your situation?

Thank you, Paul. I'll address the first question regarding the joint ventures. We previously mentioned these joint ventures, and they were primarily part of our Rattler entity before consolidation. From a financial standpoint, they are all sound investments that we expect will yield a higher return than our initial investments. The rationale behind these ventures is that we secured commercial agreements along with the financial benefits. For example, with the Gray Oak pipeline, we have 100,000 barrels a day of capacity, which remains unchanged despite selling our equity stake in the pipeline. On the gas processing front, we invested 20% in WTG, and after the deal was finalized, we and our partners decided to immediately construct cryogenic plants capable of processing 200 million cubic feet per day, which helps address gas flaring and processing issues in the Northern Midland Basin. We aim to generate value through the committed molecules linked to these investments, but eventually, it makes sense to monetize them. Regarding our inventory, we aim to drill up to 15,000 feet where possible. Most of our land in the Midland Basin is limited in terms of lateral length. Typically, for four sections running North to South, we would drill 10,000-foot laterals. If we had five sections, which is uncommon, we would undertake two sets of 12,500-foot laterals. With three sections, we would drill 15,000-foot laterals over two 7,500-foot laterals. For the FireBird deal, we focused on a lot of 15,000-foot laterals because of the large contiguous block. In contrast, the Lario area is quite landlocked in the center of Martin County, surrounded by many competitors, making it necessary to work with the lateral lengths available.

So I'll just ask, I think it was the case. I think you did touch on the M&A line of sight. I wonder if I could just dig into that a little bit more, particularly on the remaining asset sales and whether those are midstream weighted? Do you see additional opportunities in front of you that are midstream rated? And if so, are you basically looking to pay back your main exposure? I guess I'm really trying to understand how that impacts the cash flow of E&P business?

Yes, good question, Doug. Generally, we were surprised by the volume of E&P assets we sold compared to our initial expectation of $500 million in noncore asset sales, which we later increased to $1 billion. So far, we've reached $750 million. It makes sense that a significant portion of the remaining $250 million will come from noncore midstream assets. I want to point out that selling operated midstream assets will be more challenging than selling non-operated ones, like the joint ventures we mentioned in our presentation. As you suggested, operated midstream assets can affect lease operating expenses and financials, while non-operated assets have a cash flow impact that is less significant for the parent company. Therefore, it makes sense that we are focusing more on non-operated options, but for the right price, we would consider selling some operated assets, keeping in mind the potential effects on our operating metrics.

Okay. We'll see how things unfold. The raise is definitely a positive, so thank you for the clarification. I apologize for being predictable, but I need to revisit the cash tax question because it's a bit confusing. It's approximately 50% larger than the P&L tax. We are trying to determine what the normalized level of deferred tax would be when E&P kicks in at the end of this year, considering you'll have had $1 billion of earnings for three consecutive years. The $45 million in deferred tax represents about one-third of your free cash flow. Is this a straightforward question to answer?

Yes. The response is that we will exhaust all of our net operating losses in 2023, so we will be a full cash taxpayer. However, as you've pointed out, we can defer some taxes related to intangible drilling costs and the capital expenditures we invest in the business. This will depend on where commodity prices are in 2024, as well as our capital expenditures. We are committed to spending less than we earn, which logically means there will be a tax burden. However, there are too many variables right now to accurately predict 2024.

Thank you, again, to everyone for participating in today's call. If you have any questions, please contact us using the information provided. Thank you.