Thank you, Jonathan. Good morning, and welcome to Diamondback Energy's Second Quarter '22 Conference Call. During our call, 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 related 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 forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations 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.

Thank you, Adam, and welcome to Diamondback's second quarter earnings call. I'd like to start by highlighting our second quarter performance. We once again delivered operationally, producing over 221,000 barrels of oil per day, near the high end of our quarterly guidance range. Our discretionary cash flow or operating cash flow before working capital changes totaled $1.8 billion, up 27% quarter-over-quarter, setting a new high for the company. This increase was primarily due to a favorable macro backdrop, as well as improvements to our realized pricing as hedges put on last year continue to roll off. Our free cash flow for the quarter was $1.3 billion, up 35% quarter-over-quarter. We will return 63% of this free cash flow to our shareholders, well in excess of our commitment to return at least 50% of free cash flow. This return is made up of our growing and sustainable base dividend, opportunistic share repurchases, and a robust variable dividend. Our annual base dividend is now $3 per share or $0.75 per quarter, representing a 7.1% increase from the company's previous annual base dividend of $2.80 per share or $0.70 per quarter. As previously announced, the Board elected to keep our total dividend per share flat quarter-over-quarter at $3.05, which is comprised of the 75% base dividend and a $2.30 variable dividend. This puts our total annualized Q2 dividend yield at nearly 10%. Additionally, we took advantage of market volatility and repurchased nearly 2.4 million shares during the quarter at an average price of a little over $127 a share for a total cost of approximately $303 million. We believe our opportunistic, disciplined approach to our repurchase program brings the most value forward for our shareholders and continues to give us the flexibility to use either our variable dividend or buybacks, or as has been the case so far in 2022, a combination of both to hit or exceed our returns target. As we move into the second half of the year, it's hard to ignore the amount of free cash flow we expect to generate, around $2.5 billion at current strip pricing. In June, we announced an increase in our capital returns commitment target, moving it up from 50% to at least 75% of free cash flow beginning in the third quarter. At 75%, that’s over $1.8 billion to return to shareholders or well north of $10 per share in just 2 quarters, for a total annualized return yield of approximately 17%. This robust free cash flow profile led the Board to double the size of our buyback program from $2 billion to $4 billion, giving us ample running room to be opportunistic in the equity markets. Since the program was initiated in the third quarter of last year, we've repurchased over 8.3 million shares at an average price of $113 a share for a total cost of approximately $940 million. This includes 1.8 million shares we've already repurchased in the third quarter for a total of $200 million at an average price of $113.70 a share. Our confidence to increase our return through payout is rooted in the strength of our balance sheet. During the second quarter, we opportunistically repurchased $337 million in Diamondback senior notes at an average cost of 95.4% of par for a total of $322 million. We focused on our debt coming due over the next 10 years, significantly lowering our maturity towers while taking advantage of the volatile debt market. We also recently redeemed $45 million in legacy Energen and QEP notes due in 2022 at par. As a result, our balance sheet is stronger today than ever before. Our annualized net debt-to-EBITDA is under 0.7x, and we continue to improve our leverage profile with net debt decreasing by $267 million or 5% quarter-over-quarter. These debt reduction efforts have helped decrease our interest expense by 25% year-over-year, offsetting higher production taxes and lifting costs and helping push our unhedged realized cash margin this quarter to more than 83%, a company record. Moving to the operations side of the business, the environment in the Permian continues to be challenged. However, we continue to focus on how we can mitigate the inflationary pressures we're seeing across nearly all facets of the business by lowering the variable pieces of our cost structure. These efforts have allowed us to keep the high end of our capital guidance range flat at $1.9 billion. We do not anticipate any future changes. Yet we still haven't been able to offset all of the fixed pricing increases we've seen, which is why we've moved our third quarter capital range up to $470 million to $510 million, up from our capital spend of $468 million this quarter. This takes into account the roughly 10% cost increase we expect on the frac side, which is made up of increases in the cost of horsepower, wireline services, and fuel. On the drilling side of the business, we're seeing a similar level of pricing increases, particularly from day rates, casing, and cement. In the back half of this year, we plan to operate approximately 12 drilling rigs and 3 frac crews. As we mentioned last quarter, we've partnered with Halliburton to secure our first e-fleet frac crew, which will run in our Martin County acreage off power generated from a central location and delivered via existing lines, not only reducing our Scope 1 emissions profile but also lowering our completion costs as a result of fuel savings and improved operational efficiency. We expect this fleet to be operational early in the fourth quarter and it will simply be swapped in for 1 of our existing Halliburton crews. Earlier this month, we continued to lean into this technology and secured our second e-fleet crew. This crew will be operational in the first quarter of 2023 and is expected to further reduce costs and decrease our environmental footprint. It will also replace 1 of our existing crews. On the drilling side, we currently have 1 drilling rig running on offline power in the Delaware Basin with 2 more electric rigs expected in 2023. Just as we're seeing on the completion side, the electrification of our drilling fleet has multiple benefits. Additionally, we're utilizing sputter and intermediate rigs to take advantage of lower pricing as compared to the rest of our drilling fleet, and are exploring downsize and surface casing size, and intermediate hole size to improve our drilling efficiencies, pushing Diamondback even further down the cost curve. Lastly, we continue to work to earn our social and environmental license to operate. Part of this is our commitment to provide quarterly disclosures that detail our progress towards our environmental goals. We are proud of how we have performed so far this year when looking at multiple metrics, including recycling nearly 40% of our produced water and keeping our total recordable incident level at multi-year lows. However, flaring continues to be an issue. We are diligently working with our gathering partners to build in redundancy, accelerate plant turnarounds, and meet the takeaway needs of our current development plan. We remain committed to ending routine flaring by 2025 and are confident in our ability to achieve that goal. We've also spent hundreds of millions of dollars to lower our emissions profile by building pipelines and electrifying our production fields. These projects have lowered our costs to date, but due to the increase in the cost of power across the state of Texas, we have had to move our lease operating expense guidance range up by $0.50 a barrel to $4.50 to $5 a barrel. Even with this move, we continue to be the low-cost Permian operator and build on a long track record of cost control. The second quarter was a record quarter for the company. We delivered on our production guidance, kept costs in line, and distributed over 63% of our free cash flow to our shareholders. We are well-positioned to build off this momentum and are excited to begin returning at least 75% of our free cash flow to our shareholders this quarter. We expect this industry-leading cash returns program and our best-in-class operational machine to continue to deliver differentiated results for our shareholders. With these comments now complete, operator, please open the line for questions.

Our first question comes from Neal Dingmann from Truist.

My first question is about shareholder returns. Last year on your conference call, Travis, you mentioned that looking at the supply and demand fundamentals, it seemed that oil supply was still intentionally being withheld from the market, which influenced your decision to avoid production growth. Do you still think this is the case with current worldwide fundamentals, particularly concerning supply? Does this belief continue to be your main reason for not pursuing growth, or is there more influence from investor requests?

Well, certainly, as we look into 2023, I think it's a little premature to do much forecasting into 2023. But I can tell you kind of our base case is looking at something at the same activity level, probably generating something in the low single digits in terms of the growth rate. But again, it's more of an output. But I think what you specifically asked about the call last year, I think I highlighted really 3 things and then subsequently added a fourth, and that was demand at pre-COVID levels. We wanted to see 5-year inventory levels somewhere returning to the 5-year average. We still had a question about OPEC capacity. And the one I added subsequent to our call was the administration continuing to embark uncertainty into our capital allocation process across the industry. And so certainly 3 of the 4 of those have been answered today, Neal. There's still a lot of administration-led uncertainty, both in policy actions and rhetoric. But the other ones certainly appear to be answered. So I think as the industry starts to contribute towards more focus on 2023, I think you'll still be governed primarily by the shareholders who own the companies. But I do think you'll start to see a little bit of growth in the industry as we look into next year.

Great. Great response. Then my second question really, I would say is on the notable capital spend discipline that you guys continue to have. As many others we've already heard about, continue to increase their cost despite them previously saying that they were locked in. So I'm just wondering, going forward, would you all consider any type of, I don't know, like a more vertical integration or any other new strategy, or will the focus remain more or less on the same as working with vendors and just the efficient execution?

Well, Neal, I think we've been quite successful with our current model. We will always seek ways to reduce execution costs. We experienced some challenges in the first quarter due to comments about locked-in prices followed by increases in capital expenditures, which is not how we typically aim to convey our execution priorities. However, I want to acknowledge our team for their ability to manage costs effectively in an inflationary environment. About a year ago, we discussed how to distinguish between winners and losers during inflation, and it's those who can control costs that succeed. While we've focused on managing fixed costs, we've also made significant improvements in our variable costs, and I expect our team to continue this effort in 2023.

Our next question comes from Neil Mehta from Goldman Sachs.

First question is around capital returns. And you did increase the share repurchase authorization to $4 billion from $2 billion previously. It looks like you've been leaning a little bit more into the repurchase with the pullback in the stock. So if you just talk about your framework around variable dividend versus repurchases? And how you're thinking about being counter-cyclical with how you deploy your share repurchases?

Well, we certainly think that there's a lot of value in our existing stock price. And we think that, that oil and public equity stocks are really undervalued right now. And so the 2 data points that you mentioned, I think, are good indicators of future behaviors. The first being, we spent about $500 million in the last 2 to 3 months repurchasing shares. And the Board just essentially doubled our authorization up to $4 billion. So the base dividend still remains sacred, sustainable, and growing followed by this environment share repurchases. And then as we committed to a month ago, we'll make up the difference and keep our shareholders whole by returning at least 75% of free cash flow.

Yes. And then would love your perspective on the M&A outlook. We know that you've been active over the last couple of years. But is it fair to assume that given that you're prioritizing share repurchases at this point, do you think that's a better investment than third-party M&A?

Yes, certainly, Neil, that's the behavior we're demonstrating. As I just iterated, just to emphasize, all in the public markets is really cheaper than the private markets, and I think there continues to be a wide gap between those 2 points. And I think you're also seeing stalled or failed processes as well, which again indicates a spread between bid and ask. So right now, the greatest return for our shareholders is leaning into our repurchase program.

And our next question comes from Arun Jayaram from JPMorgan Securities.

Maybe just a follow-up to Neil's question, is how do you think about your process to engage in portfolio renewal in this kind of backdrop and perhaps a little bit more color, it looks like you had about $85 million of property acquisitions in the cash flow statement. I was wondering if you could provide us a little bit of detail on that? And I think on a year-to-date basis, that takes you just under $400 million of property acquisitions.

Yes. Arun, the big deal is obviously in Q1, a $230 million deal. We do capitalize a little G&A and interest which flows through that number, so it's not all property acquisitions. But a couple of things that we do on the property side, it's just the typical blocking and tackling, netting up. We give our land teams the directive that we'd rather drill 100% working interest wells across the board. And so they're always working to net up and block and tackle, but nothing of significance was purchased in Q2.

And look, Arun, being having boots on the ground here in Midland, I think all of our shareholders expect me and us to be in the deal flow at all times. But that just means we look at things coming across the desk, but I go back to say, look at what our behaviors are and the separation between public and private expectations on value. And I think that's the best way to think about what our forward plans are.

Okay. And just my follow-up is, you guys had really strong oil price realizations in the quarter. I was wondering if you could just remind us about your mix between getting waterborne crude pricing versus, call it, a Midland type of benchmark?

Yes. So we have all of our oil on pipes going to the Gulf Coast. A third of it going to Houston, getting MEH pricing, two-thirds going to Corpus getting Brent pricing. And so we've been the beneficiary of these water Brent WTI spread. We have a little bit of exposure to the Midland market, we also have the ability to kind of flex that to the Gulf Coast with the space that we have. And so the sell-off in WTI versus Brent has resulted in really good oil realizations. No guarantees that it's going to continue forever. But that kind of fits the insurance policy that we put in place to invest in these pipelines and get our barrels to the most liquid markets.

And our next question comes from Scott Hanold from RBC Capital Markets.

Could you all give us some view on what you all are seeing on leading edge inflation? And if you can give us a sense of what kind of savings you guys expect from the e-fracs versus a regular frac crew? I mean, how meaningful is that?

Yes, Scott, good question. I would say, generally, we took up CapEx on the low end and took up our average well cost estimate for the year. I would say probably today, we're probably up 15% today from the beginning of the year. We'll probably exit a little higher than that. So probably 15% year-over-year well cost increases, but what the ops team is doing is not taking every phone call and just increasing prices. We're trying to do some things to be more efficient. You mentioned the e-fleet, Travis just mentioned in his opening remarks that we're going to have a second e-fleet coming in early next year. That saves money, not just on the horsepower piece, but on the fuel piece. These will be connected to line power and the back end of a gas plant, with burning dry gas in the Permian. So while gas prices have gone up, they certainly haven't gone up as much as diesel. I would say we'd probably save $50 a foot with that e-fleet. A couple of other things we are doing on top of that, we are adding some preset rigs to replace some big rigs as those preset rigs cost a lot less with these big pads and long cycle investments. We have that ability to do so. Our team is also getting really smart on casing design and cement design. Wherever we can pick up pennies that's just our stock in trade.

A lot of pennies there you're picking up. Good to hear that. And as a follow-up, and I'm going to kind of belabor the point on shareholder returns. And I know you all have done pretty well with executing your flexible plan. But the bottom line is right now, it appears that your stock is trading at a discount to peers. I mean it looks pretty evident. And like how do you all think about like what the best way to bridge that gap is? And like what can you do to kind of force the issue to get your valuation more in line with peers or where you think it should be?

When I discuss with our Board the key indicators of our success, I focus on five of them. Three of these formed the foundation of our success in the first decade, and I believe the two additional ones will be crucial for the next ten years. The original three are execution, low-cost operations, and transparency, which have allowed us to distinguish ourselves in the market. The two new additions are capital return and decarbonization. We are now achieving a leading yield in capital return and are competitive across various shareholder return metrics. Regarding decarbonization, we are committed to both transparency in our disclosures and tangible performance improvements. These five areas represent what we are committed to, and we can provide detailed explanations of our success in each. While you've noted a gap in our stock's performance compared to peers, we are dedicated to making the right decisions for our shareholders to maximize value. Our focus is not just for the current quarter, but for the long-term future of the company.

And our next question comes from David Deckelbaum from Cowen.

Appreciate the color today. Maybe if I could ask one on just CapEx. In 2022, I think you all forecasted about 12% of your total budget going towards non-D&C. Is that a good contribution as we think about '23 and '24?

Good question, David. Historically, after a deal occurs, infrastructure and midstream typically account for 10% to 15% of total capital, eventually dropping to around 7% to 8%. I expect us to be around 7% to 8% of our total capital in 2024, following a decrease in 2023. The only caveat is that we and our peers are investing significantly in environmental cleanup, which adds an extra $30 million to $40 million annually that wasn't accounted for in the budgets from 2017 or 2018. These expenses are necessary, but I generally anticipate that our midstream infrastructure budgets will decline next year and into 2024, likely moving to 7% or 8% over the next couple of years.

As a follow-up, the capital expenditures for the third quarter will be higher than those for the fourth quarter. Looking ahead to next year, it's expected that you will be operating around 270 to 290 wells, with 12 rigs and a few frac crews. Is the $460 million guidance for the fourth quarter accurate? Should we consider a range of $460 million to $500 million as a reasonable projection for 2023, or are there specific reasons to suggest otherwise?

I think it's too early to discuss inflation for 2023. I believe we should not continually agree to margin expansion on the service side. We'll assess the situation over the next six months. As mentioned earlier, we are taking steps to improve efficiencies and reduce costs. I acknowledge your point about activity going into 2023, but I'm not ready to comment on specific aspects or projections, especially considering the factors beyond our control, like the rising cost of steel.

The only inflation I'm making then there's CapEx per share.

And our next question comes from Derrick Whitfield from Stifel.

Congrats on your quarter-end update. With my first question, I wanted to focus on your operational efficiency. Would it be safe to assume the improvement you experienced in your drilling and completion efficiency metrics over the last couple of years has at least plateaued as a result of service tightness and the dilution of experienced crews?

Yes, Derrick, I think that's a fair statement. Certainly, the business has gotten a lot harder to operate and execute this year. It's on us though to make sure we have the right supervision in the field to make sure green hands are trained up quickly. It's something that we are seeing. We do spend a lot of money near the wellhead to make sure our supervision oversees what's going on in the field. But then there's a couple of other things that kind of go the other way, right? So the spud rigs that we're putting in place, they drill a little slower, but they cost half as much as the big rigs. So I think generally, we kind of hit the efficient frontier on days of TD this year, but now we're doing some things that might slow things down, but spend less money per well.

That makes complete sense. And as my follow-up, I wanted to touch on the Inflation Reduction Act, which could be voted on this week focusing on the minimum tax and methane fee components. Could you speak to the implications for Diamondback and the industry in general? It seems at a minimum from our perspective that the one rare case that gets Diamondback would be minimized with the 15% minimum tax stipulation.

Derrick, the methane fee tax is one thing that we've looked at. And because of the dollars we've spent over the last 3 years really reducing our methane emissions, that doesn't appear, as we understand it, to be a needle mover for Diamondback.

Yes. And then on the tax side, we're pretty low on NOL protection. So if the strip holds, we have about $1 billion of protection next year, we would be above the 15% minimum that's being proposed. So I think generally moving towards a full taxpaying entity at Diamondback which mitigates the impact to us. Certainly, if we're in a different commodity price environment, it might be a different story. But in this environment, we're headed towards full cash taxes in 2024.

And our next question comes from Jeanine Wai from Barclays.

Our first question is maybe hitting on the balance sheet a little bit. So you had about $21 million of stand-alone cash at the end of the quarter, and that reflects really getting after paying off those notes early and at a very nice discount. That's great. What's the sequencing of further debt reduction that you mentioned? And do you have an updated view on your target cash balance? We're essentially kind of back to how much potential upside there could be to exceeding the 75% minimum return?

Yes, Jeanine, good question. With the rate review we expected to close at the end of August, we'll have to pay off that revolver at close. It's about a $200 million revolver that we'll expect to pay down with cash. We also want to take out the Rattler notes, $500 million notes next. There are some reporting requirements with those notes if they continue to stay out there. So I think those 2 items are certainly the priorities, and we probably expect to be in a position to have those taken out by the next time on the phone here. And then I think after that, it goes back to being selective with the other outstanding notes. You'll note that we didn't touch the 2 30-year tranches that we have out there, but we did take down some of our 29 and 31 opportunistically with a discount. But generally, the Rattler notes and Rattler revolvers coming out next and then we'll be more prudent with the rest.

Okay. Great. And then maybe a quick one on operations. I think in the past, you mentioned running 3 simul-frac crews and then potentially utilizing a spot crew. And then in your prepared remarks, I think I heard you mention just running 3 frac crews. So just wondering if I'm remembering those 2 things correctly? And have you been able to maybe drop that spot crew due to efficiencies?

Yes. The three simul-frac crews will operate continuously throughout the year. They have been active this year and will serve as the foundation for next year. We had a spot crew working during part of the second quarter and it will continue until probably the end of this year. We are trying to connect enough pads to keep the spot crew cost-effective. Danny, do you want to add anything about the spot crew?

No. I think the 3 simul-frac crews will do about 80% to 90% of our planned well activity and then the remaining 10% to 20%, we have to handle with an additional crew. We usually try to block it up and get a dedicated line of work for a crew for a period of time and then let it go and bring it back for the next group of wells.

And our next question comes from Nicholas Pope from Seaport Research.

I had a quick question about the updated CapEx guidance. The increase seems to be entirely on the drilling side, with no significant changes in expected activity. However, there hasn't been any real change in the other components, particularly the midstream environmental infrastructure. I'm curious about the inflation you're experiencing in that area. Are you anticipating the same level of activity for the nondrilling, noncompletion components, or is that more fixed with project-type work?

Yes. It's definitely a little more fixed with project-type work. There is some inflation in those budgets, but that was already somewhat baked in. On the midstream side, in particular, the big bulk items are buying a lot of pipe, and we pre-bought a lot of that. So we knew where that was going to sit on the cost side. On the infrastructure and our environmental side, it's not necessarily a change in plan. As you mentioned, it's just a few inflationary items around the edges, but it's nothing to the extent of what we're seeing on the drilling and completion side when it comes to inflation.

Got it. I appreciate that. And as you kind of look at kind of progressing towards completion of the midstream, the Rattler kind of acquisition. Is there any anticipation of any real change in operations? Or I guess, how much kind of third-party is even a part of Rattler at this point in terms of operation?

Yes. That's a great question, too. Nothing is going to change operationally. And we still like the midstream business. We still like what it does for our consolidated margins. We just felt that it didn't need to be a separate public entity, and so we're able to buy that back in and still run a midstream business that we own 100%. I will say the team has done a good job seeking out third-party opportunities. I wouldn't say it's our core business, but we'll have some real cash flow coming in from third parties given the amount of assets we have on the ground on the midstream side.

And our next question comes from Doug Leggate from Bank of America.

I hate to go back to the capital return question, but just mostly you will issue a bunch of shares. I was just wondering how we should think about split between the variable and the stepped-up buyback program as you go forward?

Yes, Doug, you were a little mixed on that. I couldn't hear you pretty well, but I think I got the gist of it. I think generally, we are going to be very aggressive on the buyback here in Q3 given where the stock is and where we continue to generate free cash above mid-cycle prices. So already expensed $200 million quarter-to-date. Generally, if you kind of take street numbers and keep our base dividend flat in Q3, we could probably spend another $650 million on buybacks this quarter. So if the stock stays where it is and oil stays where it is, we're going to be very, very aggressive on that buyback, which is why the Board signified the confidence in increasing that authorization to $4 billion.

Okay, I apologize for pressing on this point, Travis, but is there a more systematic way we can approach this? Are we still anticipating a significant variability in the second half of this year?

None of these prices, Doug, if the stock price stays where it is today, all that cash is going to go towards reducing the share count.

Great. That's what I was looking for. My follow-up is just a quick one on going back to the A&D very quickly. Can you clarify, as your understanding is today, do IDCs and I guess, NOL is not such a big deal for you guys, but in IDC specifically, do they still qualify as an offset to the A&D in your view? Any color you can offer in your interpretation of that?

I think our interpretation is they still do. Unfortunately, IDCs have become such a small part of the cash flow stream that they're not impacting things much. So that's our understanding today. But you never know if politicians, anything can happen.

And our next question comes from David Deckelbaum from Cowen.

I wanted to follow up on the discussions regarding return on capital. Travis, you mentioned your talks with the Board about how to keep Diamondback competitive with its peers. You've followed through on your commitment from last year to return 50% of 2022's free cash to shareholders and use the rest to reduce debt. Now you've increased that to 75% and raised the buyback. When you discuss return on capital programs with the Board, are there specific targets you have in mind for the buyback? How did you arrive at this amount? Are you intentionally aiming to demonstrate that Diamondback can retire over 10% of its market cap each year? Are those goals explicit now, or are they more coincidental based on the current free cash flow?

Yes, we don't have specific goals outlined in the manner you've asked. We focus on the inherent value of the stock compared to its current trading value. We aim to initiate repurchases when we see significant opportunities, like those present in today's market. This approach may evolve over time, but currently, as Kaes mentioned in response to the previous caller, we believe there remains considerable value in the stock.

And our next question comes from Vin Lovaglio from Mizuho Group.

Given the scale of free cash flow generation, I'm wondering how you guys are thinking about potential investment in future offtake, particularly on the gas side and kind of connecting that gas molecule to Gulf Coast, and ultimately, hopefully, international markets?

Yes, Vin, good question. I think just generally, while we are a pretty significant gas producer now at this point, we don't have a lot of control over the molecule. Diamondback has grown through acquisition over the years, and with those acquisitions come dedications, and most of those dedications don't come with taking kind rights. So we're certainly doing as much as we possibly can to incentivize pipeline development, getting molecules to the Gulf Coast. We did commit to the Woodford pipeline. We'll have about 1/3 of our gas on that. But generally, you have to have control of that molecule to incentivize development, and we don't have much more beyond that today.

Got it. And then I just want to go back to the e-fleets. They seem like kind of a no-brainer at this point in time. I'm just wondering, if there were any changes in planning or any hurdles that you guys kind of have to get through before broader e-fleet adoption? Or is it really just kind of securing that line power?

It's really about the quality of the fleet and what you're committing to. Halliburton has created a truly unique product. We will have battery storage integrated with the e-fleet, enabling efficient use of natural gas and electricity while the fleet operates. Large acreage blocks and big pads, like we have, are necessary, as well as a long-term partnership with a company like Halliburton. We believe we meet those requirements and feel confident about the e-fleet launching in September, to the extent that we've committed to a second one. Two-thirds of our simul-frac fleets will be e-fleets with Halliburton. When the economic and environmental benefits align, it’s an obvious choice for us. We are looking forward to deploying the first one in the field next month.

And our next question comes from Leo Mariani from MKM Partners.

I just wanted to clarify a couple of things that I heard on the call here. So in terms of the buyback, I just want to make sure I heard the numbers right. Did you guys say that you could do an additional $650 million in 3Q alone on top of the $200 million you already announced? I just want to make sure I heard that number right.

Yes. Leo, taking street numbers and multiplying it by 75%, taking out the $200 million we spent quarter-to-date and taking out the $0.75 a share base dividend, and that's your math on buybacks for the quarter. And that's something we look at every day. I mean we have our team rerun the model on a weekly basis to figure out how much cash we're going to have in the quarter to buy back shares when there's this much of a dislocation between oil in the public market then oil in the ground.

Okay. That's helpful. And then just on the debt paydown. Obviously, you talked about paying off some of the Rattler debt here. Can you maybe just give us a little more color on the decision to kind of pay off some of the paying debt, which wasn't kind of due to the end of the decade, I guess some of the 29, 30s or whatnot in the second quarter. Looked like you kind of elected to do that versus kind of pay the higher variable dividend because obviously, cash flows were up for the quarter. Just any more color kind of around the thinking there?

Yes. It's a pretty unique opportunity where E&P has a ton of cash flow and bonds trading below par. And we saw that opportunity. Our Board saw with us and decided that buying back some debt while below par was a good use of capital and also exercise accelerates that deleveraging process to give us more confidence in the increased 75% of free cash flow going back to shareholders beginning in Q3.

Okay. And just to clarify on the shareholder returns, you guys do not count debt pay down as a shareholder return, right?

That's correct.

And our next question comes from Paul Cheng from Scotiabank.

Two questions, please. Can you just remind us what is your hedging policy, if that's an official guidance in terms of what percentage that you want to hedge? Secondly, that with the rising recession period, how that impact your thought process in the 2023 budget in terms of the capital return, balance sheet management, and all that?

Yes. Good questions, Paul. I'll take the hedging policy, and I'll let Travis talk more macro about 2023. Just generally, we do buy puts for rainy days. So we've gone to the balance sheet is strengthened, we bought more and more puts around $50 to $55 Brent. In that situation, if we do go below $55 Brent, we're probably making capital decisions to slow down, but the balance sheet doesn't blow out. We can still pay our dividend and still generate free cash in that situation. So really protecting for a rainy day, trying to spend around $1.50 to $2 a barrel to buy those puts, and we want to be about 60% hedged going into a particular quarter. So if you look at our hedge book, about 60% hedged for Q3, going down to about 0% by Q2, Q3 of 2023. And we'll just continue to keep rolling that forward for rainy day insurance.

Paul, energy has historically served as a good hedge and seems likely to offset some impacts. Looking ahead to 2023, regardless of the definition of a recession, it appears that there will be recessionary effects on the economy. However, what sets this situation apart is that the world continues to be chronically short on physical barrels, with limited spare capacity to address this shortfall. While we don’t anticipate any shift in our mid-cycle outlook, it seems that the overall macroeconomic conditions are favorable for energy prices in the coming years, despite the expected recessionary impacts. Additionally, if recessionary effects do materialize, they may help diminish some of the inflationary pressures we are currently experiencing.

Yes. I'd make one more point. That's the benefit of this new business model where we're not changing our plans for every $10, $20, $30 move in oil prices. There needs to be a $50 move in oil prices lower before we discuss any change to our execution plan. And I think this level-loaded plan, level-loaded activity levels have allowed us to fight off the inflation bug a little better than most. And again, as Travis mentioned, there's no oil out there.

Just curious that when you gentlemen kind of want to keep more cash balance if that's the increasing recession fee?

Yes. Right now there is still cash. We certainly want to cash balance. The cash balance moves a lot right now, and when you're generating $1 billion of revenue a month, if the cash balance fluctuates wildly throughout each month. I think generally, having a strong balance sheet, having some cash and having access to capital through a cycle is something us and the Board discuss on a monthly basis. And I think that also ties to where your maturity profile sits, right? So if we not only have less debt, but a longer duration maturity profile, that gives us confidence in our access to capital and our ability to generate cash, given that our cash flow breakeven is down in the mid-30s a barrel.

And I am showing no further questions. I would now like to turn the call back over to Travis Stice, CEO, for closing remarks.

Thank you again for everyone for participating in today's call. If you've got any questions, please reach out to us using the contact informations provided. Thank you.

This concludes today's conference call. Thank you for participating. You may now disconnect.