Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2023 Earnings Conference Call. Please be advised that today's conference is being recorded. I would now like to hand the conference over to the VP of Investor Relations, Adam Lawlis. Please go ahead.

Thank you, Jules. Good morning, and welcome to Diamondback Energy's Second Quarter 2023 Conference Call. During our call today, we will reference an updated investor presentation and Letter to Stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO; Kaes Van't Hof, President and CFO; and Danny Wesson, COO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. 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.

Good morning, and thank you, Adam. As Adam mentioned, last night we released a shareholder letter in conjunction with our press release, and this is our second quarter in a row we've tried this. I hope you find it useful. We believe that it not only increases the transparency directly to our shareholders but also improves efficiency, and those of you who have followed our story for a long time know how important improving efficiency is to us. So with that, operator, let's move right into questions, if you'll open the line.

At this time, we will conduct the question-and-answer session. Our first question comes from the line of Neal Dingmann of Truist Securities. Your line is now open.

Morning, Travis. Nice quarter. Travis, my first question, maybe get right to it, is on service cost, and we've heard a lot of chatter about. Specifically, could you speak to maybe the current rig and frac rate environment today versus a couple of months ago? And maybe more importantly, what are you all assuming the change in cost for the remainder of the year, and how this could impact the 2024 levels?

Neal, good morning. That's a good question. When you look at our business partners on the service side, they have always been responsive to declining and increasing rig count, and the Permian Basin rig count continues to decline. With the discipline we're seeing across the E&P space and the reluctance to increase spending, we believe that we will continue to see a softening in cost from our friends on the service side. Now with that, that's only part of the calculus. The other part, which we view more as the variable side, we continue to drive cost out of the equation with increased efficiency. As we talked about in May, we also see continued input costs coming down on steel, cement, and other items. It's hard to forecast into the future, but we definitely believe we're going to see a softening in many of the costs that we've seen from the first half of the year. We also continue to rely on the organization to operate more efficiently, which they continue to do quarter over quarter.

So Travis, is it too early to call any deflation for next year at this point?

I think it's premature to call it deflation from where we're headed at the end of the year, Neal. I think high level, we entered the year in the Midland Basin at around the low 700s per foot for drilling complete and equipped costs, and we'll probably exit the year in the low 600s per foot. Again, we're not calling for a cratering of the service market; we're just anticipating a rationalization where costs certainly increased for all service lines and raw materials for seven or eight quarters, and now that's coming back down to earth a little bit. So we can kind of enter 2024 and the rest of 2023 in the low 600s per foot in the Midland Basin. That feels like a pretty good baseline for 2024.

Great. Great point, guys. My second question is on capital spend. Specifically, it looked like you slightly increased the midstream and upstream CapEx guidance very slightly. Could you give a little color on how this will be allocated for both the upstream and midstream? And what potential benefits we could see from this upturn?

Yes. I'll start with the upstream. We drilled a record amount of wells in Q2, with 98 wells drilled during the quarter. That would imply we're drilling almost 400 wells a year versus guidance at 340; so we have a lot of pipe in the ground and footage drilled, which is over a million lateral feet. It was a successful quarter operations-wise, which is why we're slowing down the drilling pace in the second half of the year and building a few DUCs, which is part of the increase in the DC&E side. On the midstream side, we have infrastructure in the Midland Basin that mostly has extra capacity. If a neighbor needs water or needs to dispose of water and we have that capacity, we will spend a few dollars to connect to that person. A few unique opportunities arose in Martin County over the last three or four months, and we're going to spend some dollars to get a lot of barrels, and that's high payback, high-return midstream spending.

Thank you. Our next question comes from the line of Neil Mehta of Goldman Sachs. Your line is now open.

Thank you so much, guys. The first question, Travis, is just on the M&A landscape in the Permian. Can you talk about whether you see a role for Diamondback to continue to be a consolidator in the basin? Additionally, could you provide an update on the asset sales, as that program has performed well for you?

I'll take those in reverse order. Regarding the deals we did earlier in the year, they've been seamlessly integrated with no issues. It's worth noting that both companies we acquired were operating more rigs than we're currently running now. The current landscape, relative to the last couple of quarters, presents limited opportunities; there was a rush primarily from private equity to get deals into the market, and now it's quite sparse. As for Diamondback's role in M&A, we have created a lot of shareholder value through our M&A approach, but our discipline has been noteworthy as well. It's not important to win every deal; it's vital that the deals enhance our quality rather than merely increasing our size. We continually hold ourselves accountable to that principle.

Thanks, Travis. The follow-up is about optimal capital structure. Could you talk about what you believe the optimal cash level and leverage level is for the business? This will help calibrate the return of capital profile for Q2?

Sure. The leverage ratio fluctuates with oil prices, but I think having a leverage ratio of less than one is appropriate for a company the size of Diamondback. I believe that building a little cash on the balance sheet is sensible to remain opportunistic for share repurchases in a countercyclical way. Those are the two key inputs we consider in our capital structure and return model.

Our next question comes from the line of Arun Jayaram from JPMorgan. Your line is now open.

Good morning, Travis and team. Both of my questions relate to CapEx. On your updated guidance, you are guiding to an $80 million decline in sequential CapEx in Q4 versus Q3. Could you help us understand the drivers of the lower CapEx in Q4 versus Q3?

Yes, Arun. I would say that the Q4 versus Q3 change is a combination of lower activity and lower costs. As you know, we're a cash CapEx payer, so we can see a few months in advance what CapEx looks like, and it's certainly coming down. Generally, that's probably the low end of a baseline for next year. A low $600 million per quarter run rate feels okay for 2024. It's early August, so we’ll keep that in pencil as service costs shake out, but it certainly seems that things are moving in our favor from a well cost perspective. I previously mentioned some cost per foot metrics, predicting a decline to the low $600s by year-end, which still feels very achievable and sets targets for the upcoming year.

Great. And you touched on the 2024 outlook, anticipating low single digits oil growth. While the Street is modeling around $650 million per quarter in CapEx, it seems you are comfortable at around low $600s.

Yes, I think that’s accurate. While several factors remain in play, the quality of our upcoming inventory and the high mineral interest in the core of the basin feels quite capital-efficient. We've highlighted this over the last couple of years, and the guidance from our transactions with QEP provides us with additional undeveloped inventory that we can use for large-scale execution.

Just as a reminder, we've been guiding for lower CapEx all year long, and we're seeing it materialize now as elaborated on Slide 6 of our investor deck with a quarterly forecast.

Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open.

Good morning all and congrats on a strong quarter.

Thanks, Derrick.

Staying on 2024, now that you've fully integrated FireBird and Lario, what is the right base level of activity that would support the 2024 outlook from a rig and frac spread perspective?

Yes. I'll highlight what we’ve accomplished in 2023 as a good baseline for capital allocation. We have a business where we can run four simul-frac crews efficiently, and each crew can complete about 80 wells a year. For us, this new business model of capital efficiency moments productivity over volume, allows us to run the most efficient plan possible with those four crews. Absent a major change in commodity price, it’s the plan, and that allows our teams to plan their business and execute at the lowest CapEx cost. Approximately 15 rigs and four simul-frac crews feels like a beneficial baseline for us.

And Derrick, just to add to that, this profitability model we’ve been demonstrating for multiple quarters in a row, along with the industry's pivot, highlights that volume growth is an output of efficient capital allocation that maximizes shareholder value. As we discuss 2024, volume growth will come from those capital allocation efficiencies.

Understood. Thanks for that, Travis. As a follow-up, I want to touch on well productivity, which you rightly highlighted as a positive. How do you view well productivity looking into 2024 and in the following few years? It seems like you have a robust portfolio that offers stability for several years.

Yes, Derrick. We feel very confident in our forward outlook for productivity. I think that's increasingly unique in North American shale. We’ve timed our deals very well, and our shift towards co-development four or five years ago aims to maintain steady productivity. We are closely tracking within 1% of 2022 levels already in 2023. A flat productivity outlook feels like a solid baseline, and any improvement is certainly advantageous.

We continue to present our inventory on Slide 16 of this deck, and my confidence in the long-term quality of our inventory is unwavering. This confidence in the future business plan correlates with our ability to steadily increase our base dividend—a clear message to our shareholders. Our quarterly compound annual growth rate (CAGR) for dividend increases is around 10% since we initiated it in 2018.

Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Good morning, Travis, Kaes, Adam, and the rest of the Diamondback team. Travis, could you elaborate on the improved cycle times allowing you to increase your gross well count for the year? Is this due to a few rigs enhancing performance or a broader trend across your fleet, potentially from bit selection or other techniques enabling quicker lateral drilling?

Charles, I wish I could attribute the improvements to one piece of technology applicable to our entire rig fleet, but it's more intricate than that. I'm going to let Danny provide specific examples. We often hear about what makes Diamondback successful, but it ultimately roots back to our culture focused on cost control and efficiency. Making these efficiency gains leads to permanent benefits in our future capital allocation decisions, enhancing our competitiveness. It is not just individual items, it's thousands of variables that we track across every rig. We maintain healthy competition among our rigs and completion crews, incentivizing them for efficiency and cost control. Danny, do you want to add specifics?

Yes. We have successfully reduced cycle times significantly, evidenced by a measurable decrease in our year-over-year days. The team diligently monitors rig metrics and swiftly addresses any divergences. Recently, we recorded a couple of wells drilled at an all-time record for us with 7,500-foot laterals completed in just over four days, which is remarkable.

Charles, just to add, during our quarterly reviews, teams present detailed metrics, even measuring the time it takes to connect pipe during every trip. While that may seem trivial, the cumulative effect of such improvements across rigs significantly influences efficiency. I want to express pride in our employees for their commitment to achieving results, such as accomplishing those four-day 7,500-foot wells.

Thank you, Travis. That reminds me of the saying, 'what gets measured gets done.' My second question pertains to the decision-making around share buybacks versus note buybacks. While you've successfully conducted note buybacks, it seems they can sometimes be overlooked since they're not direct cash returns to shareholders. How do you approach the trade-off between the two?

At the Board level, we prioritize our base dividend as the primary means of returning value to shareholders. We've established it to be both sustainable and growing, and as I mentioned this quarter, we've increased our base dividend by an additional 5%. Looking ahead, this base dividend is paramount to us and is well covered down to $40 a barrel of oil. Share buybacks depend on our expectations of future cash flows relative to stock price. As seen in recent quarters, we've committed our discretionary free cash flow toward share repurchases post-dividend. Generally, the lower the stock price, the more shares we repurchase, while higher prices yield fewer purchases. Finally, any leftover from that calculation will be returned as a variable dividend, adhering to our commitment to distribute 75% of free cash flow.

Thank you for that elaboration. I appreciate it.

Our next question comes from the line of Subash Chandra from Benchmark Company. The line is now open.

Hi. Good morning, everyone. First question, how do you view oil cuts going into '24? Is that a function of the zones you're drilling or the geographical acreage, or could factors such as gas capture impact it?

Yes, good question. We're allocating substantial capital to the Northern Midland Basin where the oil content is high, particularly at early stages. We typically guide towards a 59% to 60% oil content. In a stagnant growth scenario, that oil content will probably remain flat and could decline slightly due to oil declining faster than gas. We did have a couple of wells in the Delaware Basin earlier this year with higher gas content, but overall, I'm confident that maintaining high 50% to 60% oil content during good quarters is a practical range.

Great. And as a follow-up, I wanted to discuss asset sales. Most have been midstream. What's your perspective on the current market for upstream assets, considering oil has returned to $80 and the bid-ask spread? I've noted around $140 to $150 million in asset purchases on the cash flow statement. Is that from previously announced deals or other acquisitions?

I'll address that in two ways. On the purchase side, we've been involved in some leasing as well as a bit of netting up. We involve our asset teams in business development, and they actively make offers on undeveloped interests and non-op pieces we lack in development. We are also looking into leasing some rights in the Midland Basin linked to our holdings, contributing to some of those purchases noted in the cash flow statement. On the divestiture side, we’ve sold a considerable amount of non-core acreage that won’t compete for capital in the next decade, and we've received attractive prices. Currently, we remain on the sidelines regarding further divestiture aside from unique offers. We're focusing on non-core midstream divestitures similar to the OMOG transaction announced this quarter. We haven’t increased our non-core asset sale target; we likely won’t control the process but have more assets that could make sense to sell.

Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Hi, guys. I want to ask about production as the second quarter showed a significant outperformance versus guidance. You mentioned drilling a record number of wells in the last quarter. However, the third quarter production guide shows a slight decrease. How can you reconcile this—record drilling but a production decline? Are you holding some wells back from coming online until later this year?

Yes, Leo. Our oil guidance drives our decisions. I see Q3 as potentially flat or slightly up from Q2, but Q2 was exceptionally strong from a completions perspective. The drilling side doesn’t dictate production; rather, we might be building a few DUCs in the latter half of the year for a strong 2024. Our completion cadence was high in the first half; we completed 89 wells in Q2, with an expected drop to roughly 80 for Q3 and Q4. Our production output reflects smart, efficiency-driven decisions. If this were 2017 or 2018, we’d accelerate spending; now we’re focused on generating cash in the second half and returning that to shareholders.

That's helpful. Concerning capital, looking back at Q2, it appears CapEx peaked. Should we anticipate decreases in Q3 and Q4? How much of this relates to service costs? Do you expect service costs to be more beneficial in Q4?

Yes, we're currently experiencing the benefits of declining raw material costs, including pipe, cement, and diesel. Moving through this call and into Q3 and Q4, we expect to see more genuine service cost reductions. As we are cash CapEx payers, we're currently paying for June's activity; we have a solid forward outlook that our CapEx should be decreasing. The cost per foot we’re observing for wells being drilled today is lower than Q2, translating to reduced average well costs by year-end.

Our next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Thank you. Good morning, guys. Two questions, please. One of your large customers is highlighting their improved EUR recovery rates based on their efforts. I wonder if you’re considering this, Travis. Are you looking to pursue substantial improvements to recoverable reserves based on current technology and commodity prices?

Diamondback is a technology company that produces oil, and we're diligently working on improving EURs by observing what competitors are doing. While not too many secrets exist in the Permian Basin, if there's a better solution out there, we're committed to finding it. Our advantage lies in executing improvements at lower costs. We continuously focus on advancing EURs without expending excessive funds on trials, positioning ourselves as fast followers on effective strategies.

Based on what you see today with technology and pricing, is it economically viable for you to pursue these improvements?

I don’t believe it's economically feasible today. While some players are investing in these improvements, we prefer to allocate capital to projects with the highest returns available, specifically high-return, multi-zone developments in the Midland Basin.

Great. Regarding lateral length, you've successfully extended it, predicting about 10,800 feet for Q3. Based on your land position, do you believe there is further room to push these boundaries beyond this without significant portfolio changes?

It's a risk-reward scenario, Paul. There are areas where we can drill longer laterals. However, given today’s land position, the 10,000 to 11,000 range seems optimal. We'd prefer to drill two 10,000-foot wells over a single 20,000-foot well in terms of risk management. The drilling crew can achieve longer wells, but given the potential costs of issues at those lengths, our focus is on consistent and manageable drilling schedules.

Thank you. At this time, I would now like to turn it back to Travis Stice for closing remarks.

I appreciate everyone listening in this morning. Good set of questions. I hope you have a fantastic day. If you have any questions, reach out to us using the provided contact number.

Thank you. That concludes today's conference. You may now disconnect.