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Diamondback Energy Inc
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Good day, and thank you for standing by. Welcome to the Diamondback Energy Fourth Quarter 2022 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.
I would now like to hand the conference over to your speaker today, Adam Lawlis, VP of Investor Relations. Adam, go ahead.
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 the 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.
[Operator Instructions]
Our first question comes Neal Dingmann from Truist Securities.
Thanks for all the details, Travis. My first question is just on shareholder return topic. More than -- it's now been maybe even two years ago, certainly, more than a year ago, you mentioned way back that you thought once the macro supply demand was more in balance, you'd consider potentially more growth. I'm just wondering, has the thinking changed based on what we know of continued investor shareholder return or other factors that continue to drive sort of the environment in today?
Yes, Neal, I don't think the macro conditions are dictating any kind of production growth currently. I mean you still have an uncertain Fed action. You've got uncertainty around China COVID, demand recovery. You've still got Russian barrels that are still finding their way into the market. So it doesn't appear to me that the macro conditions have fundamentally changed. And certainly, the feedback -- and perhaps, most importantly, the feedback we get from our shareholders are encouraging us to continue to embrace a shareholder return more.
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 really leads to my follow-up just on capital efficiency. Specifically, when I look at -- by our calculation, you all pump out more free cash flow per barrel of oil than any E&P. And I'm just wondering, when you look at this driver, is that based -- is that driven largely on this co-development that you talked about? Is it capital efficiency? I'm just wondering, you all just most recently seem to be hitting all the right numbers. But I'm wondering when I look at this all important metric, what Travis or you, Kaes, would consider maybe some of the drivers of that.
Yes. It's certainly not just one thing, Neal. It's really a combination of all the things that we focus on really multiple times a day when it comes to executing our program. Certainly, well productivity enhancements add to that, but that's really an output of a very difficult decision we made in 2019 to pivot away from kind of the best two zone development strategy and embrace the multi-zone full section development strategy, which we're seeing benefits of today. You also hear us talk frequently about our cost structure and that cost structure is made up not only on the expense side where -- whether it's G&A or LOE, but also on the capital efficiency side where we continue to push the envelope, particularly on the variable cost side of things, simply doing more with less. And all of those things combined, I think, put us consistently towards the top of the most margin efficient producer in the basin.
Our next question comes from Neil Mehta from Goldman Sachs.
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 that 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. Good question as well. I think the plan when we acquired Firebird, Firebird was producing 17,000 barrels of oil a day. We guided to that asset producing 19,000 barrels of oil a day for the year 2023. So clearly, some growth on that asset we're already seeing, but we'll see the majority of that benefit going into Q2 to Q4. And then on top of that, obviously, closing the Lario acquisition on January 31, that immediately adds 6,000 net barrels a day -- or sorry, subtracts 6,000 net barrels a day from Q1 because we didn't get to count those volumes in January. So base case plan is to grow steadily from Q1 through Q4, and we got the projects to back that up.
And our next question comes from Arun Jayaram from JPMorgan Securities.
Travis, you mentioned in your prepared remarks how the company has really optimized its multi-zone co-development strategy over the last couple two, three years. I was wondering if you could provide a little bit more detail around kind of 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. Good question, Arun. In 2018 and early 2019, we were really studying this co-development strategy intently, and the significant observation that we made from our analysis was that essentially, all of these zones talk to each other. And if they talk to each other, which means you actually have pressure communication during the fracking operations, which subsequently also means that you're kind of sharing the reserves as an individual well is produced that if you don't get them upon initial -- the initial development that when you go back in later, you'll find those zones have experienced some depletion and that depletion degrades the efficiency of your stimulated rock volume, which ultimately changes the production profile. And so in order to address that, we examined our spacing assumptions, both side to side and top to bottom, and made adjustments to try to minimize those frac pressure interferences. Spread some zones out further, spread some zones above and below further, but essentially went into a section -- half of section this time was our development strategy and completed all the wells at one time and then brought them all on at one time. And that was a painful decision because it's a lot easier. In fact, I've been -- I've said it before that I'll take criticism from drilling the very best zone, but we found out that, that actually wasn't the right development strategy, and we took some things for that in 2019. But as you can see, we put some details in our -- on Slide 16, as you alluded to. We're -- in the Midland Basin, our well results are equivalent to what we were seeing in 2017.
So very proud of the technical team and their diligence to try to crack a very difficult problem and then the courage to stay with that decision through periods when we were questioned about that development strategy. So 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, great question, Arun. I think FireBird, at the end of the day, is the quintessential Diamondback deal, where we know the space and like the back of our hand and have been communicating with the FireBird team as they tested their position further West in the basin than others have in the past. And we follow the results closely and posted a couple of recent results that I think confirm a couple of things, but also give us some hope on upside in the central prospect. And there's a couple of wells sand the future may vary on the Far West side. This was probably the farthest West test to date and not an area we underwrote, and you have a very good Wolfcamp A result Far West. And then in the Southern portion of the position, you have this -- sorry, you have the four corners two-wells Wolfcamp A and Lower Spraberry. And we underwrote Lower Spraberry with Wolfcamp A upside across the central prospect, and it's looking more like you can have Lower Spraberry with Wolfcamp A co-development across that position.
So early days yet, but definitely a positive sign from the FireBird deal, and our technical team's work in getting that deal across the finish line.
Our next question comes from David Deckelbaum from Cowen.
The first question is really just a follow-up on Arun's question. [indiscernible] 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? [indiscernible] 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 that 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 [indiscernible] 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 [indiscernible] 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 a 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 next question comes from the line of Jeanine Wai from Barclays.
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, right? Q4 was going to be a great quarter going into December. We had -- obviously, we all had a winter storm here. Diamondback did not announce the winter storm impact, but certainly, the winter storm did impact our production. So going into the last 10 days of the quarter, we felt very good about where we sat and still hit guidance. And therefore, from a POP perspective, we kind of moved some wells from Q4 into Q1 to get a head start on POPs. It's not a huge capital impact, but it is a number where we guide to first production. So there's a good amount of POPS in Q1 2023 because we were ahead of schedule in Q4 and feeling good about where we started 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 really 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.
Derrick Whitfield from Stifel has our next question.
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 all performance year-over-year?
I think the biggest benefit, Derrick, is not only the assets we acquired from QEP and guide on, I think that deal while done at a tough time hit exactly what you're looking for in a transaction, right? We allocate more capital to those assets that we would have allocated to the business prior to the deals. So we're seeing a little benefit there. Those assets are also in areas where you have three or four or even five zone development, and so we're having massive pads come on in high-return areas with a little bit of a benefit on the Viper side with high mineral interest across that position. So space -- as Travis mentioned earlier in the call, taking a close look at spacing, learning from other operators in the basin, what to do and what not to do and implementing that very quickly into our plan is paying dividends.
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 6 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.
Our next question comes from Roger Read from Wells Fargo Securities.
I'd just like to maybe dive into the gas takeaway question and how you're -- I understand how you're positioned not to have Waha basis risk for the most part, but what are you looking at in terms of flow assurance this year and to the extent you can say 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.
Appreciate that. And the other question I wanted to follow up on -- I am just looking for the right page, yes, Page 23 on the hedge summary. Any thoughts on -- if we look at where Q1 has hedged, Q2 really kind of similar, is that what you'd want to do ultimately for the back half of the year as we draw in closer and it becomes more financially reasonable to do that? Or are you, at this point, more comfortable going a little less hedged just given the overall structure of the balance sheet, presumably with these dispositions coming, a little more cash coming in?
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.
Our next question comes from [Jeoffrey Lambujon] from [Perella Weinberg Partners.]
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 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. I think, generally, we guided to this year being around 15% year-over-year well costs, sub-10% from what we highlighted in November. And I would say, generally, those numbers still fit today. I would say, we're probably in the upper half of our well cost guidance for both Midland and Delaware today. But generally, there are some things coming our way outside of service cost deflation and that's another Halliburton Zeus e-fleet moving to four simul-fracs versus last year, we ran three in a spot crew. So that last simul-frac adds some efficiency. And I kind of put the budget two ways this year. I think if we see deflation, we're going to be closer to the lower half of our guide. And if we stay flat, we'll be to midpoint to the higher end. But I think generally, the anecdotes are coming in that some things are heading our way from a service cost perspective. And unlike last year, not everything -- not every line item will go up in the AFE.
And our next question comes from Scott Gruber from Citigroup.
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 kind of 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.
Our next question comes from Kevin MacCurdy from Pickering Energy Partners.
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.
Our next question comes from Leo Mariani from ROTH MKM.
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 you've got just a couple things that are impacting LOE. First, we're fairly exposed to the power market, and we rode through the back half of last year fairly unhedged through the -- we're up in gas prices and that really impacted our real-time power pricing, and you've seen kind of real-time power pricing kind of stay a little elevated through the first part of 2023 here. And so trying to guess where we're going to land with respect to power and have an opportunity to get hedged to protect ourselves, but -- so that's adding about a dime. And then you've got another impact from the FireBird acquisition with about 900 vertical wells, which had another dime or two to our consolidated LOE. So between those two things, you're looking at about a quarter, and we think we're probably running in the lower end of the guide today. And if we see some things come our way, we think we could potentially be under the guide, but we're not baking that into our guidance.
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.
Our next question comes from Paul Cheng from Scotiabank.
In your presentation, you show a number of the energy ownership that in the pipeline and gas processing. Just curious that if any of those that you will consider strategically important for you to own their equity ownership? Or that -- I mean just trying to see that I mean, whether any of them have that strategic importance to you? Second question is that when we're looking at your inventory backlog, for those you consider over 10,000 feet, lateral length, you roughly say, call it, 5,500. Just want to see if we can drill a little bit more into that, and what percentage of those wells you can actually do maybe 3-miles? And whether there's an opportunity for trade and swap that you think you may be able to improve on that?
Great. Thank you, Paul. I'll take the first one on the JVs. We did highlight all of these JVs. I think generally, these all sat at our Rattler entity before consolidating it. Generally, from a financial perspective, I think they're all good investments that eventually will be monetized at higher value than what we paid -- what we put in. But the strategy behind why we did these things is that we got commercial agreements and benefits locked in with the financial piece. So whether it's -- like the Gray Oak pipeline, right? We got 100,000 barrels a day of space on the pipeline, that's not changing even though we sold our equity interest in the pipe. On the gas processing side, we invested 20% into WTG. We and our partners decided to build 200 million a day cryo plants immediately after closing the deal, and that is alleviating a lot of the gas flaring and gas processing issues in the Northern Midland Basin. So we try to drive value through molecules committed to these investments, but generally, at some point, it makes sense to monetize them.
On the inventory side, we try to drill 15,000 feet wherever we can. I think most of our land in the Midland Basin is pretty locked up from a lateral length perspective. I think generally, if we had four sections North to South, we would drill through 10,000-foot laterals. If we had five sections North to South, which is rare, we would drill two sets of 12,500 foot laterals. And if we had three sections, we would drill 15,000-foot laterals over two 7,500-foot laterals. So we underwrote the FireBird deal with a lot of 15,000 footers because that is a big contiguous block. And on the other side, Lario, pretty landlocked in the center of Martin County with a lot of competitors around. So we kind of had to live with the lateral length as they were presented.
[Operator Instructions] Our next question comes from Doug Leggate from Bank of America.
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. I would say, generally, we were surprised at the amount of E&P assets we sold relative to initial expectations of $500 million of noncore asset sales because we raised that to $1 billion. We're at $750 million to date. It's logical that most of those -- most of the rest of the $250 million or more come from noncore asset comes from midstream assets. I will say if they're -- it's going to be harder for us to sell operated midstream assets versus non-op midstream assets like the JVs that we highlighted in the back of our deck like you inferred, operated midstream assets do have an impact on LOE and financials. Whereas non-operated assets, you do have a cash flow impact from less distributions from those assets, but not as meaningful to the parent co. So I think it's logical that more non-op stuff is top of mind, but for the right value, some operated stuff would be on the table. Just we'd be cognizant of what that would do to our operating metrics.
Okay. I guess we'll watch and see how -- the raise is obviously a positive. So thanks for the clarification. Guys, I apologize for being predictable. I'm going to put myself in the cross-hairs a little bit and go back to the cash tax question because it's through a sort of bit of a loop, to be perfectly honest. But it's about 50% bigger than the P&L tax. And what we are trying to figure out is, when E&P kicks in, which I guess would be the end of this year because you'll have had $1 billion of earnings presumably for three consecutive years, what in the $45 million of deferred tax, it's about 1/3 of your free cash flow, what do you think the normalized level of deferred tax would be if the conditions were the same? Is that an easy question to answer?
Yes. I mean, I guess the answer would be, we're going to get through all of our NOL in 2023. So that will be exhausted, and we'll be a full cash taxpayer, although as you mentioned, we will be able to defer some with respect to intangible drilling costs and the CapEx we spend on the business. So I guess it will be dependent upon where -- obviously, where commodity prices are in 2024. And second to that, where CapEx is, I think we're obviously in a world where we're going to be spending -- continue to spend less than we make. So it's logical that there will be a tax burden. There's just too many variables right now to predict 2024.
With no further questions, I would like to hand it back to Travis Stice, Chairman and CEO, for closing remarks. Travis?
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.
Okay. That's it for today's conference. This does conclude the program. You may now disconnect. Thank you.