Diamondback Energy (FANG) Q4 2022 Earnings Call Transcript

Diamondback Energy (FANG 0.43%)
Q4 2022 Earnings Call
Feb 22, 2023, 9:00 a.m. ET

Contents:

• Prepared Remarks
• Questions and Answers
• Call Participants

Prepared Remarks:

Operator

Good day and thank you for standing by. Welcome to the Diamondback Energy fourth quarter 2022 earnings conference call. [Operator instructions] After the speakers' presentation, there will be a question-and-answer session. [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.

Adam Lawlis -- Vice President, Investor Relations

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 non-GAAP measures.

Reconciliation with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Travis Stice -- Chairman and Chief Executive Officer

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 location, equipment availability, and weather-related downtime. However, 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 to our base and variable dividends, with a total dividend growth of nearly five times 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 positioned 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 to 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 in our invested capital and use 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 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 do not compete for immediate capital within our portfolio. We have now increased our noncore 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 2050s at an average coupon of below 5%. We will continue to use free cash flow and proceeds from our noncore assets sales to lower our overall debt profile, continually improving our financial position. As we move into 2023, we expect to deliver a 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, and continued 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.

Questions & Answers:

Operator

OK. Thank you. Yes, we will conduct a question-and-answer session. [Operator instructions] OK.

Our first question comes from Neal Dingmann from Truist Securities. Neal, your line is open.

Neal Dingmann -- Truist Securities -- Analyst

Morning. Thanks for all the details, Travis. My first question is just on shareholder return topic [Inaudible] More than -- 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 today?

Travis Stice -- Chairman and Chief Executive Officer

Yes, 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, and 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. 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 mode.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. I think also on top of that, Neal, you know, we're going to be growing oil production per share significantly in 2023, you know, through two well-timed acquisitions and a significant amount of buybacks in 2022. So, you know, first-year 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 the steady state of activity has produced good results today, and no need to change that while it's working right now.

Neal Dingmann -- Truist Securities -- Analyst

Good point, Kaes. That really leads to my follow-up just on capital efficiency. Specifically, what 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 based -- you know, is that driven largely on this, you know, co-development that you talked about? Is it capital efficiency? I'm just wondering, you all just most recently, you know, seem to be hitting all the right numbers.

But I'm wondering, when I look at this all-important metric, what's -- you know, Travis, you or Kaes would consider maybe some of the drivers of that.

Travis Stice -- Chairman and Chief Executive Officer

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 zones 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. And that cost structures made up not only 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, you know, simply doing more with less. And all of those things combined, you know, I think put us consistently, you know, toward the top of the most margin-efficient producer in the basin.

Neal Dingmann -- Truist Securities -- Analyst

Great answer. Thanks, guys.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Neal.

Operator

Please stand by for our next caller. OK. Our next question comes from Neil Mehta from Goldman Sachs. Neil, your line is open.

Please go ahead.

Neil Mehta -- Goldman Sachs -- Analyst

Yeah, good morning, Travis, Kaes, and team. 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?

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, Neil, great question. You know, I think we announced, you know, two E&P asset sales, noncore assets sales this quarter that I think fit the mold of what the market looks like right now. And that's, you know, assets that don't compete for capital in our capital plan, you know, for many, many years and, you know, 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, you know, these two deals, the buyers are going to, you know, get aggressive developing these two assets right away, which, you know, and the capital allocators -- is just good capital allocation from our perspective.

And going into it, we expected to sell more midstream assets, you know, 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, you know, monetized. Gray Oak, I think, was a great example.

We retained all of our commercial benefits of the transaction. You know, we still move our barrels to the Gulf Coast. It's 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, you know, we're going to be patient and prudent when it comes to selling assets.

Neil Mehta -- Goldman Sachs -- Analyst

Yeah, that's a 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.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. Good question as well. You know, I think the plan -- you know, 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, you know, 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, 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, subtract 6,000 net barrels a day from Q1 because we didn't get to count those volumes in January. So, you know, base case plan is to grow steadily from Q1 through Q4.

And, you know, we've got the projects to back that up.

Neil Mehta -- Goldman Sachs -- Analyst

Thanks, Kaes.

Operator

Stand by for our next question. And our next question comes from Arun Jayaram from J.P. Morgan Securities. Arun, your line is open.

Please go ahead.

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

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 couple of two or three years. I was wondering if you could provide a little bit more detail around kind of what you're doing today.

And on Slide 16, you gave us a lot of great detail on the amount of net Lario footage by zone, but wondering 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 and just your thoughts on sustaining the level of well productivity gains that you generated last year into the future.

Travis Stice -- Chairman and Chief Executive Officer

Yeah. Good question, Arun. You know, 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, you know, pressure communications 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, 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 depletion degrades the efficiency of your simulated raw volume, which ultimately changes the production profile. And so, 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, frac pressure interferences, spread some zones out further, spread some zones above and below further, but essentially went into a section -- half of the section at the time was our development strategy and completed all the wells at one time and then brought them all on at one time. And, you know, that was a painful decision because it's a lot easier. In fact, I've been -- I've said it before that, you know, 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 pain for that in 2019. But as you can see, we put some details in our -- on our Slide 16, as you alluded to. You know, we're -- in the Midland Basin, our well results are equivalent to what we're seeing in 2017. So, we're 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 questioning about that development strategy.

So, I hope that answers your question, Arun.

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

That's helpful. And 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-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, you know, assessment of locations that you paid for.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. Great question, Arun. You know, I think FireBird, at the end of the day, is the quintessential Diamondback deal, where we know this base 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. And, you know, we followed the results closely and posted a couple of recent results that I think, you know, confirms -- confirm a couple of things, but also give us some hope on upside in the central prospect.

And, you know, there's a couple of wells that in the future may vary on the far west side. You know, 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 the Sallie -- sorry, you have the Four Corners two wells, Wolfcamp A and then Lower Spraberry.

And we wrote -- 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.

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

Thanks a lot, gentlemen.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Arun.

Operator

Stand by for our next caller. Our next question comes from David Deckelbaum from Cowen. David, your line is open. Please go ahead.

David Deckelbaum -- Cowen and Company -- Analyst

[Technical difficulty] Kaes, good morning. The first question was really --

Kaes Van't Hof -- President and Chief Financial Officer

Good morning, David.

David Deckelbaum -- Cowen and Company -- Analyst

Thank you. Yeah, the first question is really just a follow-up on Arun's question. [Technical difficulty] seen a somatic of your peers testing additional zones this year. Maybe can you give us a sense of that 330 or 350 wells you're doing this year? [Technical difficulty] current inventory.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. David, you're breaking up a little bit there, so I'm going to 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?

David Deckelbaum -- Cowen and Company -- Analyst

That's correct. Sorry about that.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, no problem. So, 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 a sale of Robertson Ranch in the central Martin County area. So, 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 Prospect, which covers that -- those deeper zones, a terra structure on the eastern side of the Midland Basin, where we're going to be developing some Woodford and Barnett. Generally, you know, we're probably going to drill three or four wells there this year. I don't think it's going to be, you know, 10, 15-plus. But, 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. So, if those zones start getting leased up, it's a great benefit to the Diamondback-Viper relationship.

David Deckelbaum -- Cowen and Company -- Analyst

Appreciate that. And then [Technical difficulty] 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 this [Technical difficulty] on '22 or '21?

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, again, breaking up a little bit, but you're 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. And so, those two deals have a higher decline rate than the base business.

But I think we manage that in our guidance and also manage that in how we're going to complete wells across the pro forma position. So -- and 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 moving oil price, right? We -- 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.

David Deckelbaum -- Cowen and Company -- Analyst

Thanks for the answers, guys, and sorry for the reception.

Kaes Van't Hof -- President and Chief Financial Officer

No problem.

Operator

OK. 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.

Jeanine Wai -- Barclays -- Analyst

Hi. Good morning, everyone. Thanks for taking our questions.

Kaes Van't Hof -- President and Chief Financial Officer

Hi, Jeanine.

Travis Stice -- Chairman and Chief Executive Officer

Hello, Jeanine.

Jeanine Wai -- Barclays -- Analyst

Hi. Good morning. Our first question, maybe 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.

So, that's great. For 2023, the number of wells for sale looks a little bit higher than what we would have expected if we just used, you know, 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.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, Jeanine. You know, 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 a winter storm, in fact, but certainly, the winter storm did impact our production.

So, you know, 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, you know, we kind of moved some wells from Q4 to 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.

Jeanine Wai -- Barclays -- Analyst

OK, great. Thank you. 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 or just -- really just checking in if there's any change in how you're viewing the variable versus the buyback? Thank you.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, 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 -- 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 buyback 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. And so, you know, 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. And I think you can expect us to keep doing that.

And then having the variable, you know, be the output of what base dividend post-buybacks doesn't get through in the particular quarter.

Jeanine Wai -- Barclays -- Analyst

All right. Thanks, gentlemen.

Kaes Van't Hof -- President and Chief Financial Officer

Thank you, Jeanine.

Travis Stice -- Chairman and Chief Executive Officer

Thanks, Jeanine.

Eric. Are you there, Eric? We can't hear you.

Adam Lawlis -- Vice President, Investor Relations

Next question, Eric. 

Operator

Pardon me. Derrick Whitfield from Stifel has our next question. Derrick, please go ahead. Your line is open.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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

Kaes Van't Hof -- President and Chief Financial Officer

Thank you, Derrick.

Travis Stice -- Chairman and Chief Executive Officer

Thanks, Derrick.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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?

Kaes Van't Hof -- President and Chief Financial Officer

You know, I think 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 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. So, 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.

And so, 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. So, you know, space -- 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.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

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?

Kaes Van't Hof -- President and Chief Financial Officer

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 going to count on it until we see it. But, you know, casing has moved up from what's called $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 is going to ease. It's not -- that'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, you know, highly efficient. It 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, you know, use less fuel, but also run on, you know, 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 a, you know, inflationary environment.

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Terrific. Well done, guys. Thanks for your time.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Derrick.

Travis Stice -- Chairman and Chief Executive Officer

Thanks, Derrick.

Operator

And our next question comes from Roger Read from Wells Fargo Securities. Roger, your line is open. Please go ahead.

Roger Read -- Wells Fargo Securities -- Analyst

Yeah, thank you. Good morning.

Kaes Van't Hof -- President and Chief Financial Officer

Good morning, Roger.

Travis Stice -- Chairman and Chief Executive Officer

Good morning, Roger.

Roger Read -- Wells Fargo Securities -- Analyst

Good morning. I just like to maybe dive into the gas takeaway question and how your -- I understand how your position 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?

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. 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. So, all those contracts are with, you know, private equity-backed or some of the public gatherers and processors in the basin. So, I feel really good about our flow assurance in our contracts.

You know, the issue is going to be price. And 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. But 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. And I think that generally is going to move the issue further downstream.

So, it's going to be a tight, tight gas market in the Permian. The Henry Hub prices obviously aren't helping as well. But, you know, we feel good that the gas will move, and we're well hedged financially to protect from that downside.

Roger Read -- Wells Fargo Securities -- Analyst

OK. Appreciate that. And 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 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, 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?

Kaes Van't Hof -- President and Chief Financial Officer

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. But, you know, we don't want to put that in harm's way.

So, 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% to 60% hedged going into a particular quarter on oil, you know, down to 0% hedge, you know, four or 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 the year, we'll grow as we go through the year.

Roger Read -- Wells Fargo Securities -- Analyst

OK, great. Appreciate it. Thanks.

Kaes Van't Hof -- President and Chief Financial Officer

Thank you.

Operator

Just bringing our next caller up. OK. Our next question comes from Jeffrey [Inaudible] from Perella Weinberg Partners. Jeffrey, your line is open.

Please go ahead.

Unknown speaker

Hey. Good morning, everyone. Appreciate you all taking my questions.

Travis Stice -- Chairman and Chief Executive Officer

Good morning, Jeff.

Kaes Van't Hof -- President and Chief Financial Officer

Hi, Jeff.

Unknown speaker

Just a couple from 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 material 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 just lastly on this, how we should think about the bounds 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, you know, how 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 the last quarter earnings.

Kaes Van't Hof -- President and Chief Financial Officer

Good question, Jeff. You know, I think, generally, you know, we got to this year being around 15% year over year while 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.

But generally, you know, there are some things coming our way, you know, outside of service cost deflation. And that's, you know, another Halliburton Zeus 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. And, you know, I kind of put the budget two ways this year.

I think if we see deflation, you know, we're going to be closer to the lower half of our guide. And if we stay flat, we'll be at the midpoint to the higher end. But I think, you know, 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.

Unknown speaker

Perfect. Sounds like a better outlook. Thank you.

Travis Stice -- Chairman and Chief Executive Officer

Thanks, Jeff.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Jeff.

Operator

Stand by while I can connect the next caller. And our next question comes from Scott Gruber from Citigroup. Scott, your line is open. Please go ahead.

Scott Gruber -- Citi -- Analyst

Yes. Good morning. I want to 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.

But do you think the e-frac additions will be additive to the improvement in cycle times, you know, above and beyond what you're seeing from simul-frac?

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, 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, the e-fleets, on a fuel efficiency basis, not just the type of fuel, but the efficiency of the fuel used is -- 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.

And, Danny, do you want to add anything on that?

Danny Wesson -- Chief Operating Officer

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.

So, 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.

Scott Gruber -- Citi -- Analyst

Got it. 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'll hit your D&C costs? You know, 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 are we really talking about a 2024 benefit just given your contracts kind of in place at this juncture?

Danny Wesson -- Chief Operating Officer

Yeah. 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, you know, we certainly have some protections in place on some of our consumables. But if we start seeing, you know, the market softening, 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. And, you know, we certainly have not seen a lot of upward pressure on pricing in the first part of this year. It's been pretty quiet.

And, you know, hopefully, we'll start seeing some help on the inflation front here through the second and third quarter.

Scott Gruber -- Citi -- Analyst

Got it. I appreciate the color. Thank you.

Operator

Stand by for one moment. Our next question comes from Kevin MacCurdy from Pickering Energy Partners. Kevin, your line is open. Please go ahead.

Kevin MacCurdy -- Pickering Energy Partners -- Analyst

Thanks, and congratulations on the great free cash flow quarter. It looks like cash taxes came in well under expectations. In 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.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. 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. It came with about $100 million of midstream assets and some other fixed assets that, you know, we're able to depreciate right away. And so, that allowed us to defer more taxes into 2023. You know, as we've modeled 2023, you know, we still have about $1 billion NOL that will be exhausted this year.

But on top of that, also closing the FireBird and Lario transaction, which added some, you know, midstream and fixed assets as well. So, you know, generally, this is, you know, kind of our last year before being a full cash taxpayer. We got two well-timed deals that 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.

Kevin MacCurdy -- Pickering Energy Partners -- Analyst

Great. It's nice to see that cash going directly to the shareholders as well. Thank you for my question.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Kevin.

Travis Stice -- Chairman and Chief Executive Officer

Thanks, Kevin.

Operator

Stand by. Our next question comes from Leo Mariani from ROTH MKM. Leo, your line is open. Please go ahead.

Leo Mariani -- MKM Partners -- Analyst

Yeah. Hi, guys. I was hoping you could talk 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.

Travis Stice -- Chairman and Chief Executive Officer

Yeah, I think, you know, we got just a couple things that are impacting LOE. First, we were fairly exposed to the power market, you know, and we rode through the back half of last year barely unhedged through the run-up in gas prices. And that really impacted our real-time power pricing. And you're seeing that kind of real-time power pricing kind of stay a little elevated through the first part of 2023 here.

And so, you know, trying to guess where we're going to land with respect to power and have an opportunity to get hedge to protect ourselves. But, you know -- so that's adding about a dime. And then you've got another, you know, impact from the FireBird acquisition with, you know, about 900 vertical wells, which add, you know, 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.

Leo Mariani -- MKM Partners -- Analyst

OK. I appreciate that. And then just on M&A. Obviously, you guys were, you know, 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.

Kaes Van't Hof -- President and Chief Financial Officer

Yeah, I don't know if sellers are ever reasonable, Leo, but 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, you know, than peers. And that is -- you know, when you underwrite PUDs, that drives value to the good guys even if you're not running the strip oil pricing. So, 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.

So, it's relatively quiet at the moment. But, you know, some of the smaller things that tend to trend with the large deals like, you know, the blocking and tackling, the couple other deals that FireBird and Lario were working on, you know, when they sold, that's the kind of stuff that we're focused on right now.

Leo Mariani -- MKM Partners -- Analyst

OK. Thanks.

Kaes Van't Hof -- President and Chief Financial Officer

Thank you, Leo.

Operator

I am bringing our next caller on. OK. Our next question comes from Paul Cheng from Scotiabank. Paul, your line is open.

Please go ahead.

Paul Cheng -- Scotiabank -- Analyst

Thank you. Good morning, guys.

Kaes Van't Hof -- President and Chief Financial Officer

Good morning, Paul. 

Paul Cheng -- Scotiabank -- Analyst

Good morning. In your presentation, you show a number of the equity ownership that is in the pipeline and gas processing. Just curious that if any of those that you would 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 well 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. Thank you.

Kaes Van't Hof -- President and Chief Financial Officer

Great. Thank you, Paul. I'll take the first one, you know, on the JVs. 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, 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, you know, whether it's like the Gray Oak pipeline, right? We're going to 100,000 barrels a day of space in 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. You know, we and our partners, you know, 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, you know, we try to drill 15,000 feet wherever we can. I think most of our land in the Midland Basin is, 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 where 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, you know, the Lario, pretty landlocked, you know, in the center of Martin County, with a lot of competitors around. So, we kind of have to live with the lateral lengths as they were presented.

Paul Cheng -- Scotiabank -- Analyst

Great. Thank you.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Paul.

Operator

[Operator instructions] Our next question -- stand by. Our next question comes from Doug Leggate from Bank of America. Doug, your line is open. Please go ahead.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

Thanks, guys. So, I'll just ask -- I think -- or was it Kaes? 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? And 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.

Kaes Van't Hof -- President and Chief Financial Officer

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 noncore assets sales because we raised that to a billion. We're at 750 million to date. You know, it's logical that most of those -- most of the rest of the 250 million or more that's come from noncore assets sales comes from midstream assets.

I will say if there -- it's getting 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, you have -- do have a cash flow impact from less distributions from those assets but not as meaningful to, you know, the parent co. So, 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.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

OK. I guess we'll watch and see how -- the raise is obviously a positive, so thanks for clarification. Guys, I apologize for being predictable. I'm going to 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. And what we are trying to figure out is when the E&P kicks in, which I guess would be the end of this year, because you'll have about $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 -- 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?

Kaes Van't Hof -- President and Chief Financial Officer

Yeah. I mean, I guess the answer would be, you know, we're going to get through all of our NOL in 2023, so that'll be exhausted, so we'll be a full cash taxpayer. Although, as you mentioned, you know, we will be able to defer some with respect to, you know, simple drilling costs and, you know, the capex we spend as a business. So, I guess it'll be dependent upon, you know, obviously, where commodity prices are in 2024.

And second to that, you know, 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. But it's just too many variables right now to predict 2024.

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

OK. I know it's a tough one to answer. Thanks, guys.

Kaes Van't Hof -- President and Chief Financial Officer

Thanks, Doug.

Operator

OK. With no further questions, I would like to hand it back to Travis Stice, chairman and CEO, for closing remarks. Travis.

Travis Stice -- Chairman and Chief Executive Officer

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.

Operator

[Operator signoff]

Duration: 0 minutes

Call participants:

Adam Lawlis -- Vice President, Investor Relations

Travis Stice -- Chairman and Chief Executive Officer

Neal Dingmann -- Truist Securities -- Analyst

Kaes Van't Hof -- President and Chief Financial Officer

Neil Mehta -- Goldman Sachs -- Analyst

Arun Jayaram -- JPMorgan Chase and Company -- Analyst

David Deckelbaum -- Cowen and Company -- Analyst

Jeanine Wai -- Barclays -- Analyst

Derrick Whitfield -- Stifel Financial Corp. -- Analyst

Roger Read -- Wells Fargo Securities -- Analyst

Unknown speaker

Scott Gruber -- Citi -- Analyst

Danny Wesson -- Chief Operating Officer

Kevin MacCurdy -- Pickering Energy Partners -- Analyst

Leo Mariani -- MKM Partners -- Analyst

Paul Cheng -- Scotiabank -- Analyst

Doug Leggate -- Bank of America Merrill Lynch -- Analyst

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