Value add is name of the game as operators evaluate vendors, investments, commercial models

Hunter Landers is Senior VP of Completions at Diamondback Energy.

From an E&P perspective, what would you say are the biggest long-term challenges the drilling and completions industry faces today?

I think one of the biggest challenges is retaining talent. From the operator’s standpoint, that means retaining the same talent for each job – that would be the drillers and all the associated services that it takes to make it happen out there. We use all kinds of strategies to retain contractors, like performance incentives or compensation, and we’ve seen success using those strategies to keep the crews together, both on drilling and completions. 

For us, keeping the same people on location working together every day is like keeping a symphony orchestra together. There are 10 or 20 providers out there at any given time working together to make it all work as one, so it’s very important that everybody is used to working together and knows each other’s moves. That enables us to stay efficient, but keeping that high-level talent out there is always a challenge, and that’s what we’re still going through today.

For the rig contractors, I think the challenge is more around the reduction in activity due to increased efficiency. The North American land market has seen a pickup in efficiency in the past year or so. If we were planning to drill X amount of wells before, we’re still drilling the same number of wells, but we’re drilling them with fewer rigs – and that’s not unique to Diamondback. 

That is making for a little bit of an imbalance in supply and demand, and probably is making some rig rates go down, which makes it more challenging when the rig contractors have already gone through a pretty tough challenge with the COVID downturn.

This makes it hard on the market. It makes it hard on people to make business plans and execute on them when the goal posts keep moving. For the rig contractors, they have to keep finding ways to stay competitive and profitable.

So you have your network of preferred providers. Do you find that challenging to maintain in the current market?

We’re always checking the market more for value than for price. You can get some incredibly cheap prices for services at low value. But still, the name of the game right now is capital efficiency, which is what we’re all held to. Sometimes it’s hard to define how much value we’re getting for a given service.

I think that our group tries to put a lot of effort into defining the value, but as far as keeping them together, we acknowledge that sometimes we don’t have a lot of control. Even beyond price, say a crew quits from a particular company that we’re using on a certain rig, we can’t request them. We don’t have any control over that.

Like I said, we provide some performance incentives that keep people wanting to work on a Diamondback location from the contractor side. The incentive can’t be just to achieve a milestone – it has to be value based. Whatever you’re paying out, you have to capture some of that value to make it worthwhile. 

If you can strike that balance, that is a huge aid in retention.

Do you see capital discipline continuing for the near-term future?

The shareholder community is messaging a priority on returning free cash, capital efficiency and capital discipline, so that is what we are doing, as well.

Moreover, on a macro basis, there is excess supply in the world, which is not a signal to grow. We want to exercise the sort of discipline that allows us to weather the commodity price cycles. 

In order to develop the systems that push efficiencies further, you need to prioritize investing in innovation. From an operator standpoint, what role does Diamondback play in that investment?

Diamondback isn’t a huge spender on R&D for new things. We like to have a high level of certainty with systems. 

It goes back to capital efficiency and what’s asked of us from our shareholders. We’re going to be a fast follower if something’s working. We’ve proven through our acquisitions that we are a fast follower, and we’ll try to take advantage of an emerging technology as soon as we can. But we have a low risk tolerance for investments that we don’t know will pay off. We are not going to develop new things without some level of certainty.

That being said, there’s still fruit left on the tree. I think we can continue pushing rotary steerable development, and we can further optimize the drill bit as we continue making these long runs, but you have to look at those innovations on a case-by-case basis. If a company has had success with a particular bit technology and has been able to overcome previous limitations with that technology, then sure, we will try it. But if we try that bit, then the bit makes it 1,000 feet and we have to make a trip, then we’re not going to try that again, no big deal. 

But we’re not risk tolerant for some things that could really negatively impact your program. It’s a case-by-case basis, and everybody has a different tipping point and a different mentality on the value that could be brought by trying something new or different. We just don’t feel like there’s a huge advantage to us taking a lot of risk for that. 

What about automation? Does Diamondback see value in that?

Again, it comes back to value. Are those technologies going to be as dependable as what we have, or are they going to come at a cost? Is automation going to create value for us? If so, what does that look like? Industrywide, I think there are definitely people looking at more remote and automated processes, especially with drilling, and automation could come into play in the future. 

What equipment do you need to have on a rig that you’re contracting these days? 

I wouldn’t say it’s a case of must haves. Obviously, you’re going to have horsepower specs and weight specs, but that’s just marrying up your program with a rig. For us, the main things we’re looking for are getting quality people on quality crews, both on the rigs and the ancillary services. You want reliable equipment that’s not operating at the peak of its capacity – you want something that allows you to push the limits. You want equipment with enough capacity for growth in your program, whether that means longer laterals, more weight or faster pumping. 

You want some additional capacity left in your setup so you can keep growing the program. If we need 2,998-hp on a project, then we don’t want a 3,000-hp pump. We want 4,000 hp. You need the capacity to go further than what your needs are. 

The industry is getting more and more efficient, and getting more lateral feet out of a rig than in the past. That begs the question of what impact that efficiency will have on rig counts moving forward. Is it wise to look at rig count as a be-all, end-all for assessing the strength of the drilling market?

For sure, if you’re looking at the market signals through rig count alone, especially in the past year or two, the data is not trending like it used to. 

We watch the rig count just like everybody else, but at the same time, we’re looking at lateral feet. You can’t even look at lateral feet from a per-well basis unless your rig efficiency and lateral length are relatively static – that metric doesn’t scale. So you have to look at lateral feet drilled per year or lateral feet turned to production per year as a key metric of whether the market is growing or contracting. How many lateral feet did a company drill this year versus last year? What’s their projected rig count going to be? If the rig count is shrinking, you might have a better idea as to why. 

If we’re drilling the same amount of lateral footage year over year and have the same frac design, and our sand consumption isn’t changing, our rig count might still change drastically because we’re drilling longer laterals with more efficient rigs.

How do you view the nature of collaboration between yourself as an E&P and the rig contractors?

While the service companies are the ones who dream up the next big thing, in order for them to even brainstorm on that, we have to be good communicators to them on what our expectations are. They have to know what we’re trying to achieve. Generally, these guys want to help us achieve our goals, because that’s what provides value.

Every operator’s goals are going to be a little bit different, so the nature of collaboration is, again, going to be case-by-case. As an industry, we just have to be good communicators. The rig contractors have to understand what our drivers are so that they can provide more purpose-built solutions.

Do you think the commercial models we have right now offer the best alignment between E&Ps and drilling contractors? If not, how can we align?

Again, it goes back to the case-by-case basis between operators and drilling contractors. Some people will be better off using a dayrate model, and some people are going to prefer a performance-based contract. A lot of times, though, it’s a gray area depending on the operator’s needs and the drilling contractor’s needs.

The goal is to get everybody aligned on efficiency and upside. You could have a hybrid dayrate model that protects us and the drilling contractors from the downside of performance and benefits both of us if there’s an upside. The performance incentives have to create value for there to be alignment, and that value has to be mutual. You need open-mindedness on both sides in order to come to the best agreement. You can’t just put everything in a box.

We’re now seeing laterals that were once thought impossible becoming much more commonplace. Is the equipment on the drilling rigs today sufficient to push lateral lengths even further?

I think so. I don’t see a ton of challenges on the drilling side. It actually gets a bit more complex on the completion side with the wireline runs and drill-outs, just because you’ve spent so much money by the time you get there, it can be really tough if you have a problem. 

If you haven’t even run production casing yet and you run into an issue while drilling, you can sidetrack and just lose a portion of the wellbore. But if we have trouble 1 mile into a 4-mile lateral, we’ve already spent most of our money there, so it’s a little higher risk profile on the completion side. There are also a few more challenges with drill-outs and cleaning out wellbores to those depths at low pressures. 

After we frac, we see much lower pressures in the wells than we did before, especially in the upper zones, and in the Permian – where we’re based – it’s pretty challenging to keep circulation. We’re trying to pump down that pipe at much higher rates, so you have friction and impact.

I would say most of the challenges seem to be on the completion side with the longer laterals. But, you know, I remember arguing in 2013 about whether we could do 10,000-foot laterals instead of 7,500 feet. Less than a year later, the whole program was running at 10,000 feet. No matter the challenges, we tend to figure things out. 

You mentioned the challenges with wireline. How far do you think we are in bridging the gaps technology-wise so that we can mitigate the potential operational issues on longer laterals?

I think it’s just a matter of everybody getting comfortable. We’ve already done enough 4-mile laterals that we would not refuse to drill a 4-mile lateral just for operational issues. We might realize that there’s a little bit more risk and a little bit more challenge in it, but it’s nothing that makes us uncomfortable to do the project. 

Now, there’s always the question of, every time you step out, are you still getting the same reserve ratio? As you step out, you’re going to have to keep validating that you’re still recovering the same reserve ratio to justify the efficiency of drilling those wells. But we haven’t seen an issue to this point, so I don’t see why you wouldn’t keep pushing the lateral lengths.

With all the technology we’re seeing on a land rig today, how long would you say a rig’s useful life is? Do you think we’re going to come to a newbuild cycle any time soon? 

I don’t really know what a rig’s useful life is because I feel like they keep going through upgrade processes. Any conversations we’ve had with the rig contractors have been more around it being a better deal to do some sort of modification or revamp to a rig rather than build a new one to accomplish the same thing. It comes back to defining what we want to accomplish. Does it really require a newbuild rig, or can we accomplish that with a conversion or upgrade?

That’s going back to my earlier question about the shift in how we look at the market. It seems like this industry’s adapted to a new reality of newbuild cycles not being something to look forward to.

Exactly. Also, if you look at those other factors I mentioned like lateral footage per year – if that’s flat and the footage per year per rig is going up, maybe some of those older rigs are retiring themselves out anyway. Those rigs will get old eventually. 

Let me circle back to your earlier point about keeping people in the fold. The recruitment of young professionals and college students seems to be a huge challenge for the industry today. Are we doing as much as we can to bring young people into the fold?

For the industry, probably we haven’t done everything we could do. I think the root of the problem might be just the perception of our industry in general. It’s not so much the case in Midland, where we’re based, but just throughout the country. Young people might not see a future in our industry, just from things that have been put out there. Why would I want to go be a petroleum engineer when we’re only going to use oil for another five years? That’s a narrative that’s fairly widespread and probably damaging. 

This is something we need to think about, because it needs to be addressed earlier than just during college recruiting. What if, because of the negative perception of our industry, these kids don’t major in petroleum engineering? Diamondback does tons of career fairs and university recruiting, but we also need to engage more with young people, maybe in junior high or high school. 

How do you address that? Well, we do things like tutoring programs, STEM camps and robotics programs. I would like to think that we are having a good impact on the youth of the community, to help them realize that this is a good career to have. However, most of these efforts are in Midland. The wider industry should be doing those types of things all over the place, so that we can have a cumulative effect on how our industry is perceived by young people going to college. That’s something we could do better as an industry. DC