Good day. Thank you for standing by. Welcome to the Diamondback Energy Fourth Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during the session, you'll need to press star one one on your telephone. That's star one one. You'll hear an automated message advising that your hand is raised. To withdraw your question, press star one one again. 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'll 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'll make reference to certain non-GAAP measures. The reconciliation with the appropriate GAAP measures can be found on our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice. Thank you, Adam. Welcome to Diamondback's 4th 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 simultaneous 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. Through it all, 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 a total dividend growth of nearly 5 x when compared to 2021. In total, we returned $11.31 per share in dividends. In the 4th 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 at $3.20 per share annually, or $0.80 per quarter, representing 54% year-over-year growth. We also announced multiple strategic transactions in the 4th 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 evaluate both our Rattler-operated assets and equity method investments, we've also monetized multiple non-core upstream positions. We have now divested nearly $600 million in upstream assets since the 3rd 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 non-core asset target sale from $500 million to at least $1 billion by the end of this year. Last year, we improved our leverage ratio, now below one times, and also pushed the tenor of nearly 90% of our debt past five years, with over $2 billion due in the 2050s at an average coupon of below 5%. We will continue to use free cash flow and proceeds from our non-core 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 four 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, continued to produce one of the highest margin barrels in the industry. Looking ahead, our business model is working. 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. Thank you. Yes, we'll conduct a question and answer session. As a reminder, to ask a question, you'll need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from Neal Dingmann from Truist Securities. Neal, your line is open. Morning, thanks for all the details, Travis. My, my first question is just on shareholder return topic du jour. I think it's now been maybe even two years ago, certainly more than a year ago, you mentioned, way back that you thought, you know, once the macro supply and demand was more in balance, you'd consider potentially more growth. I'm just wondering, has this thinking changed based on what we know of continued investor shareholder return or other factors that continue to drive sort of the environment we're in today? Yeah, Neal, I don't think the macro conditions are dictating any kind of production growth currently. I mean, you still have, you know, an uncertain Fed action. You've got uncertainty around the China COVID demand recovery. You've still got Russian barrels that, you know, are still finding their ways into the market. It doesn't appear to me that the macro conditions have fundamentally changed. Certainly the feedback, and perhaps most importantly, the feedback we get from our shareholders are encouraging us to continue to embrace a shareholder return model. Yeah, I think also on top of that, Neal, you know, We're gonna be growing oil production per share significantly in 2023, you know, through two well-timed acquisitions and a significant amount of buybacks in 2022. You know, per share metrics continue to improve. We continue to invest in high return projects while not having to change our, you know, activity plan on a monthly basis trying to follow the crude price. You know, 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. Yeah. Yeah. Yeah. Good point, Kaes, that might really leads to my follow-up just on capital efficiency. Specifically, when I look at, you know, by our calculation, you all pump out more free cash flow per barrel of oil than any E&P, and I'm just wondering, you know, when you look at this driver, is that base, you know, is that driven largely on this, you know, co-development that you talked about as a capital efficiency? I'm just wondering, y'all just most recently, you know, seem to be hitting all the right numbers. I'm wondering when I look at this all-important metric, which, you know, Travis, you or Kaes would consider maybe some of the drivers of that. Yeah. It's certainly not just one thing, Neal. It's really a combination of all the things that we focus on, you know, 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, you know, kind of the best two zone development strategy and embrace, you know, the multi-zone full section development strategy, which we're seeing benefits of today. You also hear us talk frequently about our cost structure, that cost structure is made up not only the expense side, where whether it's G&A or LOE, but also on the capital efficiency side, where, you know, we continue to push the envelope, particularly on the variable cost side of things, you know, simply doing more with less. All of those things combined, you know, I think put us consistently, you know, towards the top of, you know, the most margin-efficient producer in the basin. Great answer. Thanks, guys. Thanks, Neil. Please stand by for our next caller. Our next question comes from Neil Mehta from Goldman Sachs. Neil, your line is open. Please go ahead. Yeah. Good morning, Travis, Kaes, team. The first question I had was around non-core asset sales. You did bump your target from half a 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? Yeah, Neil, great question. I think we announced, you know, two E&P asset sales, non-core asset sales this quarter that I think fit the mold of what the market looks like right now. That's, you know, assets that don't compete for capital in our capital plan, you know, for many, many years. You know, a little bit of PDP associated with those assets. Generally, a buyer that is looking to develop those assets a lot faster than we're planning. You know, these two deals, the buyers are gonna, you know, get aggressive developing these two assets right away, which, you know, in the capital allocators, it's just good capital allocation from our perspective. You know, going into it, we expected to sell more midstream assets, you know, than E&P assets, so that's why we bumped the target. We still have some strategic midstream investments that are nearing the point where they should be, you know, monetized. Gray Oak, I think was a great example. We retained all of our commercial benefits of the, of the transaction. You know, we still move our barrels to the Gulf Coast. It's just that from a financial perspective, the pipeline was a great investment. It worked, and we monetized it to the partners. I'd expect more more on the midstream side. We did highlight what we have from a midstream perspective in the deck for the first time. You know, we're gonna be patient and prudent when it comes to selling assets. Yeah, that's great perspective. The follow-up is the oil volume guide for the full year was solid, Q1 a little bit softer. 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. Yeah. Good question as well. You know, I think the plan, you know, when we acquired 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. You know, clearly some growth on that asset we're already seeing. We'll see the majority of that benefit going into Q2 to Q4. On top of that, you know, obviously closing the Lario acquisition on January 31st, you know, that immediately adds, you know, 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. You know, base case plan is to grow steadily from Q1 through Q4. You know, we got the projects to back that up. That's good. Standby for our next question. Our next question comes from Arun Jayaram from J.P. Morgan Securities. Arun, your line is open. Please go ahead. Yeah, good morning, gentlemen. Travis, you mentioned in your prepared remarks how, you know, the company has really optimized its multi-zone co-development strategy over the last, a 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 give us a lot of great detail on the amount of net lateral footage by zone. I wonder to understand what you're doing to maybe mitigate some of the issues we're seeing from the industry in terms of, you know, parent-child interference and impacts from delayed targets? Just your thoughts on sustaining the level of well productivity gains that you'd generated last year into the future? Yeah, good question, Arun. You know, in 2018 and early 2019, we were really studying this co-development strategy intently. The significant observation that we made from our analysis was that essentially all of these zones talk to each other. If they talk to each other, which means you actually have, you know, pressure communication during the fracking operations, which subsequently also means that you're kind of sharing the reserves as a, as an individual well is produced, that if you don't get them, you know, upon initial, the initial development, that when you go back in later, you'll find those zones have experienced some depletion, and that de-depletion degrades the efficiency of your stimulated rock volume, which ultimately changes the production profile. In order to, in order to address that, you know, we examined our spacing assumptions both side to side and top to bottom, and made adjustments to try to minimize those, you know, frack pressure interferences, spread some zones out further, spread some zones above and below further, but essentially went into a section, half a section at a time was our development strategy, and completed all the wells at one time and then brought them all on at one time. You know, that was a painful decision because it's a lot easier. In fact, I've said it before that, you know, I'll take criticism from drilling the very best zone. We found out that actually wasn't the right development strategy, and we took some pain for that in 2019. As you can see, we put some details on slide 16, as you alluded to. You know, we're in the Midland Basin, our well results are equivalent to what we were seeing in 2017. 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, you know, through periods when we were questioned about that development strategy. I hope that answered your question, Arun. That's helpful. Maybe just a follow-up. I wanted to get some thoughts on some of the initial well results from FireBird. You know, I believe in that transaction, you guys underwrote just over 350 gross locations, but you highlighted some potential upside based on co-developer 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? Yeah. Great, great question, Arun. You know, I think FireBird, at the end of the day is the quintessential Diamondback deal where we know this basin like the back of our hand and had been communicating with the FireBird team as they tested their position further west in the basin than others had in the past. You know, we followed the results closely and posted a couple recent results that I think, you know, confirm a couple of things, but also give us some hope on upside in the central prospect. You know, there's a couple wells, the Nakisha Mayberry on the far west side. You know, this was probably the farthest west test to date and not an area we underwrote. You have a very good Wolfcamp A result, far west. Then in the southern portion of the position, you have the Sally, sorry, you have the Four Corners, two wells, Wolfcamp A and then Lower Spraberry. You know, we underwrote Lower Spraberry with Wolfcamp A upside across the central prospect. It's looking more like you can have Lower Spraberry with Wolfcamp A co-development across that position. 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. Thanks a lot, gentlemen. Thanks, Arun. Stand by for our next caller. Our next question comes from David Deckelbaum from Cowen. David, your line is open. Please go ahead. Kaes, good morning. Good morning, David. Thank you. The first question was 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 330-350 wells you're doing this year than current inventory? Yeah, David, you were breaking up a little bit there, so I'm gonna try to repeat what I thought you said, which is, you know, what other zones are we testing outside of our traditional development zones across the basin. Is that correct? That's correct. Sorry about that. Yeah, no problem. You know, generally, right, the majority of our capital is going to be allocated to the best zones, co-development, you know, a big development this year in kind of the sale in Robinson Ranches in the central Martin County area. That's where the majority of capital is getting deployed. You know, certainly there are deeper tests going on throughout the basin. You know, we have our Limelight prospects, which covers that, those deeper zones, a terrace structure on the eastern side of the Midland Basin, where we're gonna be developing some Woodford and Barnett. Generally, you know, we're probably gonna drill three or four wells there this year. I don't think it's going to be, you know, 10, 15 plus. You know, I think generally promising results from the deeper zones across the basin and the benefit of, you know, 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. If those zones start getting leased up, it's a great benefit to the Diamondback Viper relationship. Appreciate that. The 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? How does decline to what you on 2022 or 2021? Yeah. Again, breaking up a little bit, but talking about base declines, you know, I think the base business, obviously the base decline continued to decrease since being in maintenance mode from 2020. You know, we did add, you know, two acquisitions in FireBird and Lario where they, you know, had built a lot of rate, very quickly. Those two deals have a higher decline rate than the base business. I think we managed that in our guidance and also managed that in how we're gonna complete wells across the pro forma position. Certainly base declines 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, you know, $5 or $10 a barrel. Thanks for the answers, guys. I'm sorry for the reception. No problem. Okay, stand by for our next caller. Our next question comes from the line of Jeanine Wai from Barclays. Jeanine, your line is open. Please go ahead. Hi. Good morning, everyone. Thanks for taking our questions. Hi, Jeanine. Hello, Jeanine. Hi. Good morning. Our first question may be just following up on David's questions there on capital efficiency. Capital efficiency looked great in Q4, and you turned the sales about 55 net wells, and you hit oil when your guidance, we think, implied like 73 net wells. 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 used, you know, the amount of wells you did in 2022, we add in the Lario and the Firebird deal wells. Are we looking at that math correctly for 2023? Any color you would have would be helpful since including the divestitures, we still think the 2023 outlook looks conservative, and we're assuming that the priority is really to beat on CapEx and not volumes? Yeah, Jeanine. you know, I think a couple things, right? Q4 was gonna be a great quarter. going into December, we had obviously we all had a winter storm here. you know, Diamondback did not announce a winter storm impact, but certainly the winter storm did impact our production. you know, going into the last 10 days of the quarter, we felt very good about where we sat and still hit guidance. Therefore, from a POP perspective, you know, we kind of moved some wells from Q4 into Q1 to get a head start on POPs. Not a huge capital impact, but it is a number where we guide to first production. There's a, you know, 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. Thank you. 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. Thank you. Yeah. Yeah. No change, Jeanine. Really, the variable is the output of how many shares we didn't buy back in a particular quarter. You know, the buyback is still gonna be very opportunistic. I think, you know, I think now that we've kind of gone through this for four or five quarters, you can see that, you know, 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, you know, right now. You look back at a quarter like Q4, you know, bought back less shares in October and November, but, you know, hit the buyback very hard in December. I think you can expect us to keep doing that and then having the variable, you know, be the output of what base dividend plus buybacks doesn't get through in a particular quarter. Great. Thanks, gentlemen. Thank you, Jeannine. Thanks, Jeanine. Derrick, are you there? We can't hear you. Next question, Eric. Pardon me. Derrick Whitfield from Stifel has our next question. Derrick, please go ahead. Your line is open. 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 development sequencing impacts, are there 1 to 2 primary drivers that would explain the improvement you observed in well performance year-over-year? You know, I think the biggest, the biggest benefit, Derrick, is not only, you know, the assets we acquired from QEP and Guidon. You know, I think that deal, while done at a, at a tough time, you know, hit exactly what you're looking for in a transaction, right? We allocated more capital to those assets than we would have allocated to the business prior to the deals. We're, we're seeing a little benefit there. You know, those assets are also in areas where you have, you know, three or four or even five zone development. You know, we're having massive pads come on in high return areas with a little bit of a benefit on the Viper side, you know, with high mineral interest across that position. You know, as Travis mentioned earlier in the call. You know, taking a close look at spacing, you know, 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. 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? You know, the biggest headwind over the last six quarters has been casing costs. Now, you know, we can certainly see around the corner that maybe we're seeing some softening there. You know, I'm not gonna count on it until we see it. You know, casing has moved up from, let's call it $40 or $50 a foot to $110 a foot. It's 20% of a Midland Basin well cost now, and that's a significant headwind over the last six quarters. I think that headwind's gonna ease. That's a little bit out of our control. The things that we can control are the efficiencies gained from simul-frac operations. We'll probably have four simul-frac crews running by, you know, Q2 of this year, which is, you know, highly efficient and saves about $30 a foot versus conventional crews. On top of that, two of those crews are going to be the Halliburton e-fleet, Zeus crews. Those, you know, use less fuel but also run on, you know, cheap Waha gas right now. That saves another $15 or $20 a foot. We're doing what we can to cut costs and keep costs as low as possible in a, in a, you know, inflationary environment. Perfect. Well done, guys. Thanks for your time. Thanks, Derrick. Thanks, Derrick. Our next question comes from Roger Read from Wells Fargo Securities. Roger, your line is open. Please go ahead. Yeah. Thank you. Good morning. Good morning, Roger. Morning, Roger. Morning. I'd just like to maybe dive into the gas takeaway question and how I understand how you're positioned not to have Waha basis risk for the most part. What are you looking at in terms of flow assurance this year and to the extent you can say next year? Yeah. Good, good question, Roger. You know, I don't think flow assurance is going to be an issue for us. You know, but we are exposed to the Waha price based on how the contracts are written. You know, through the history of Diamondback, we've been very acquisitive, and when we acquire things, it comes with contracts. All those contracts are with, you know, private equity backed or some of the public gas pro-gatherers and processors in the basin. I feel really good about our flow assurance and our contracts. You know, the issue is gonna be price. What we've seen in the basin is, you know, some tightness coming out of the basin on Waha, when pipelines have gone up or gone down over the last six months. Really, you know, 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. I think that generally is going to move the issue further downstream. It's going to be a tight gas market in the Permian. You know, Henry Hub prices obviously aren't helping as well. You know, we feel good that the gas will move, and we're well hedged financially to protect from that downside. Okay. Appreciate that. The other question I wanted to follow up on, I'm just looking for the right page. Yeah, page 23 on the hedge summary. Any thoughts on if we look at where Q1 is hedged, Q2 really kind of similar, is that what you'd wanna do ultimately for the back half of the year as we draw in closer and it becomes more financially, you know, reasonable to do that? Or are you, at this point, more comfortable, you know, going a little less hedged, you know, just given the overall structure of the balance sheet, presumably with these dispositions coming, you know, a little more cash coming in? Well, great, you know, great question, Roger. We don't believe in no hedges, I think primarily because our, you know, our balance sheet is a hedge, our cost structure is a hedge, but we consider our base dividend debt, right? Our base dividend is now $3.20 a share. It's almost $550 million of outflows a year. You know, we think it's well protected today at $40 a barrel. You know, we don't wanna put that in harm's way. You know, we buy puts as fire insurance and, you know, we basically use the front quarter to extend duration three or four quarters out. We try to be 50%-60% hedged going into a particular quarter on oil, you know, down to 0% hedged, you know, four or five quarters out. I think you can continue to expect us to do that. Your observations are 100% correct that, you know, the back half of the year will grow as we go through the year. Okay, great. Appreciate it. Thanks. Thank you. Just bringing our next caller up. Okay, our next question comes from Jeoffrey Lambujon from Perella Weinberg Partners. Jeffrey, your line is open. Please go ahead. Hey, good morning, everyone. Appreciate y'all taking my questions. Good morning, Jeff. Hey, Jeff. Just a couple from me, follow-ups on the service cost environment and Diamondback read-through specifically. You know, I appreciate the comments on what you're watching for and, you know, how Diamondback is positioned to really maximize what y'all can control. 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. You know, I guess lastly on this, how we should think about the bounds of the CapEx guide for this year in that context? The second part of my question is just looking for a snapshot of, you know, how well costs 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 with last quarter's earnings. Good question, Jeff. You know, I think generally, you know, we guided to this year being around 15% year-over-year well costs, you know, sub 10% from what we highlighted in November. You know, I would say generally those numbers still fit today. I would say, you know, we're probably in the upper half of our well cost guidance for both Midland and Delaware today. Generally, you know, there are some things coming our way, you know, outside of service cost deflation. That's, you know, another Halliburton e-fleet, you know, moving to four simul-fracs versus last year we ran three in a spot crew, so that last simul-frac adds some efficiency. You know, I kind of put the budget two ways this year. I think if we see deflation, you know, we're gonna be closer to the lower half of our guide, and if we stay flat, we'll be to midpoint to the higher end. I think, you know, generally the anecdotes are coming in that some things are heading our way from a service cost perspective. Unlike last year, not everything, not every line item will go up in the AFE. Perfect. Sounds like a better outlook. Thank you. Thanks, Jeff. Thanks, Jeff. Standby while I connect the next caller. Our next question comes from Scott Gruber from Citigroup. Scott, your line is open. Please go ahead. Yes, good morning. I wanna circle back on the completion efficiency comments. You know, e-frac obviously brings pretty good fuel savings, given the gas diesel spread here and obviously, associated ESG benefits. Do you think e-frac additions will be additive to the improvement in cycle times, you know, above and beyond what you're seeing from simul-frac? You know, I think generally, Scott, they complete a similar amount of lateral feet as the simul-frac crews, as we're seeing early time. On top of that, the e-fleets on a fuel efficiency basis, not just the type of fuel, but the efficiency of the fuel used is 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, you wanna add anything on that? Yeah, I think, you know, we've only been running the first crew for about six months and, you know, we've been really impressed with the performance thus far. It's outperformed our other fleets kind of on the margin, but, you know, not too measurable. We do believe that over time you'll see, you know, that gap widen in performance. Just really believe that the maintenance required around the e-fleet equipment will be substantially less. You know, we're excited to learn through that with Halliburton and, you know, recognize some added efficiencies on top of just fuel savings as we go forward. Got it. If, if service costs, you know, do start to slip in the Permian with Anvil rigs and frac crews coming out and migrating over, how quickly do you think that'll hit your D&C costs? You know, you know, if that starts to kind of pivot here in the near future, is it an ability for you to realize that in the 2nd half? Or are we really talking about the 2024 benefit, just given your contracts kind of in place at this juncture? Yeah. I mean, we don't really have any long-term contracts in place. We, you know, we kinda have shorter cycle pricing agreements. I think generally we're exposed to market pricing across the board. You know, we certainly have some protections in place on some of our consumables. If we start seeing, you know, the market soften, which, you know, we feel like is a pretty good likelihood with where we see, you know, gas prices today, that should trickle down into the oil basins, you know, particularly on the drilling services side of things first. You know, we've certainly not seen a lot of upward pressure on pricing in the first part of this year. It's been pretty quiet. You know, hopefully we'll start seeing some help on the inflation front here through the 2nd and 3rd quarter. Got it. I appreciate the color. Thank you. Stand by for one moment. Our next question comes from Kevin MacCurdy from Pickering Energy Partners. Kevin, your line is open. Please go ahead. Thanks. Congratulations on the great free cash for the 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. Yeah, good question, Kevin. You know, the biggest benefit we did receive in the 4th quarter, obviously, you know, commodity prices came down quarter-over-quarter Q3 to Q4. That was a surprise to the positive on cash taxes. I guess that hurts you overall. You know, the biggest deferral we got was when we closed the FireBird deal, and that came with about $100 million of midstream assets and some other fixed assets that, you know, we're able to depreciate right away. That allowed us to defer more taxes into 2023. You know, as we've modeled 2023, you know, we still have about $1 billion of NOL that will be exhausted this year. On top of that, also closing the Fire or the Lario transaction, which added some, you know, midstream and fixed assets as well. Generally this is, you know, kind of our last year before being a full cash taxpayer, but two well-timed deals allowed us to push out a little more cash. You know, obviously, it's not the reason why we do the deals, but it's a nice tangential benefit. Great. It's nice to see that cash going directly to the shareholders as well. Thank you for my question. Thanks, Kevin. Thanks, Kevin. Standby. Our next question comes from Leo Mariani from Roth MKM. Leo, your line is open. Please go ahead. Yeah. Hi, guys. I was hoping you could talk a little about LOE trends. Just looking at the guide here, in 2023, you guys are expecting LOE to come up a little bit, kind of versus where it was in 2022. Maybe just a little color around what you're sort of seeing there? Yeah. I think, you know, we've got just a couple things that are impacting LOE. First, we're fairly exposed to the power market, you know, and we rode through the back half of last year fairly unhedged through the, you know, the run-up in gas prices, 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. You know, trying to guess where we're gonna land with respect to power and have an opportunity to get hedged to protect ourselves. You know, so that's adding about $0.10. Then you've got another, you know, impact from the FireBird acquisition with, you know, about 900 vertical wells, which adds, you know, another dime or two to our consolidated LOE. Between those two things, you're looking at about a quarter. You know, we think we're probably running in the lower end of the guide today. If we see some things come our way, we think we could, you know, potentially be under the guide. We're not baking that into our guidance. Okay. Appreciate that. Just on M&A, obviously you guys were, you know, helpful in terms of talking about some of these non-core asset sales. I think you did mention in your prepared comments that perhaps some of those proceeds could go, you know, to bolt-ons out there in the space. 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? 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 2023? Yeah. I don't know if sellers are ever reasonable, Leo, but, you know, generally I do think, you know, the two larger transactions did happen because, you know, 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, you know, than peers. That is, you know, when you underwrite PUDs, that drives value to the, to the good guys, even if you're not running strip oil pricing. I think, I think generally that's what's happened. You know, there's less and less large opportunities like the two that we announced last fall. You know, it's relatively quiet at the moment. You know, some of the smaller things that tend to trend with the large deals like, you know, the blocking and tackling, a couple other deals that FireBird and Lario were working on, you know, when they sold, you know, that's the kind of stuff that we're focused on right now. Okay, thanks. Thank you, Leo. I am bringing our next caller on. Okay. Our next question comes from Paul Cheng from Scotiabank. Paul, your line is open. Please go ahead. Thank you. Good morning, guys. Morning, Paul. You know, good morning. In your presentation, you show a number of the equity ownership that in the pipeline and gas processing. I'm just curious that if any of those that you will consider is strategically important for you to own the 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 are 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 well you can actually do maybe three miles and whether that there's opportunity for trade and swap that you think you may be able to improve on that? Thank you. Great. Thank you, Paul. I'll take the first one, you know, on the JVs. You know, we did highlight all these JVs. I think generally, you know, these all sat at our Rattler entity, you know, before consolidating it. Generally, you know, from a financial perspective, I think they're all, you know, good investments that eventually will be monetized at higher values than what we paid or what we put in. The strategy behind why we did these things is that we got commercial agreements and benefits locked in with the financial piece. You know, whether it's like the Gray Oak Pipeline, right? We have 100,000 barrels a day of space on the pipeline. You know, that's not changing, even though we sold our equity interest in the pipe. On the gas processing side, you know, we invested 20% into WTG. We and our partners, you know, decided to build two 200 million a day cryo plants immediately after closing the deal. That is alleviating a lot of the gas flaring and gas processing issues in the Northern Midland Basin. 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, you know, we try to drill 15,000 feet wherever we can. I think most of our land in the Midland Basin is pretty, you know, pretty locked up from a lateral length perspective. I think generally, if we had four sections north to south, we would drill two 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. If we had three sections, we would drill 15,000-foot laterals over 2 7,500-foot laterals. You know, we underwrote the FireBird deal with a lot of 15,000 footers because that is a big contiguous block. On the other side, you know, Lario, pretty landlocked, you know, in the center of Martin County with a lot of competitors around. We kinda had to live with the lateral lengths as they were presented. Great. Thank you. Thanks, Paul. Just a reminder, if you have a question, please press star one one on your telephone and I will see that your hand is raised. Our next question. Standby. Our next question comes from Doug Leggate from Bank of America. Doug, your line is open. Please go ahead. Thanks, guys. Travis, I think there was a 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 weighted? If so, are you basically looking to pare back your midstream exposure? I guess I'm really trying to understand how that impacts the cash flow of E&P business. Yeah, good question, Doug. You know, I would say generally, we were surprised at the amount of E&P assets we sold relative to initial expectations of $500 million of non-core asset sales. Because we raised that to $1 billion, we're at $750 to date. You know, it's logical that most of the rest of the $250 million or more come from non-core asset sales comes from midstream assets. I will say if they're... It's gonna 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. You know, like you inferred, operated midstream assets do have an impact on LOE and financials, whereas non-operated assets, you know, do have a cash flow impact from less distributions from those assets, but not as meaningful to, you know, the parent co. I think it's logical that more non-op stuff is top of mind, but for the right value, you know, 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 it progresses. The raise is obviously a positive, so thanks for the clarification. Guys, I apologize for being predictable. I'm gonna put myself in the crosshairs a little bit and go back to the cash tax question because it threw us for a bit of a loop, to be perfectly honest. It's about 50% bigger than the P&L tax. What we are trying to figure out is when AMT 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. That's in the $45 million of deferred tax. It's about a third of your free cash flow. What would the... 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? Yeah. I mean, I guess the answer would be, you know, we're gonna get through all of our NOL in 2023, so that'll be exhausted. We'll be a full cash tax payer. Although, as you mentioned, you know, we will be able to defer some with respect to, you know, in terms of drilling costs and, you know, the CapEx we spend as a business. I guess it'll be dependent upon where, you know, obviously, where commodity prices are in 2024. Second to that, you know, where CapEx is. I think we're obviously in a world where we're going to continue to spend less than we make. It's logical that there will be a tax burden. There's just too many variables right now to predict 2024. Okay. I know it's a tough one to answer. Thanks, folks. Thanks, Doug. Okay, 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.