Current PXD Stock Info

As oil and gas companies dive into the Q4 earnings season in the coming days and weeks, more and more chief executives at E&Ps and oilfield service companies will share their insight as to their recent operations, thoughts about where the industry is headed, technological advancements and plans for 2018.

Catching up with some of the earnings calls from the past week, for this story Oil & Gas 360® reproduced selected Q&A from some of the Q4 calls.

Pioneer Natural Resources (ticker: PXD)

Q: Looking at your production growth trajectory outlined in the presentation, the climbing cash flow, breakeven oil prices, and total cost structure, free cash flow looks to expand pretty substantially even at the forward strip, which is backwardated. Given the shareholder-friendly actions that you guys have initiated today, is that basically trying to provide incremental line of sight to us in terms of how that cash flow or free cash flow will expand? And as free cash flow is generated, should we expect it to be returned to shareholders?

President and CEO Timothy L. Dove: First of all, as I mentioned in the call, we’ve taken a first step towards returning cash to shareholders here by virtue of increasing the dividend and announcing this share repurchase program regarding basically buying back creep from long-term incentive plan shares that are granted to employees for compensation.

What we’ll do in the face of what you commented on is evaluate that situation over time. It’s very clear if you look at the modeling associated with this that we should be generating very substantial free cash flow, seriously in billions of dollars over the plan period, and that’s based on a $55 and $3 case.

So we’ll be evaluating that through time. And as we head towards a free cash flow generation model, hopefully it’s this year. It very well may be next year, of course, with the volatility in commodity prices. We’ll make the next set of decisions at the board level. But for the time being, we believe we’re taking a good first step, and then we’ll be evaluating that as we go forward.

Q: And just to that point, in terms of the future build-out of the vertical integration, how do you plan to invest between company-owned fleets and third-party fleets on a go-forward basis?

Timothy L. Dove: I think we’ve really been the beneficiary through time of owning our own vertical integration when it comes to pumping fleets. And the reason I say that is, when times are really strong, as they were in 2010 through 2014, we quickly paid for all of our equipment investment when margins were 100%-plus. When margins have been lousy in the downturn, we’ve been able to keep active, which is one of the reasons to make sure we maintain our RPMs of the organization, but in doing so we keep our employees. And so we’re ready to roll with our six or seven fleets in any given time coming out of the downturn, where others are scrambling to get people. So there’s tremendous value in owning our own pumping fleet.

Now that said, we do use one outside fleet today, and the decisions going forward are surrounding just the basic buy-versus-lease decisions. We know if we own these fleets, we can control our own destiny, we can control the costs, and we can make sure that they’re there when we need them there. But there are a lot of great companies that are pumping wells as well. ProPetro has done a fantastic job for us as a third-party provider. And so that would be the model example of someone we might want to bring in as more third-party fleets.

This is in the fullness of time something we’ll have to evaluate. In our case, we have two fleets that we’re considering revamping and renovating that would put us up to nine fleets. That would certainly take care of us for the next year or two. At that point in time, we’ve got some decisions to make.

Q: When I look at the 3.0 completions, which continue to perform quite well and, Tim, you said it’s something that you’re basically going to evaluate midyear and then determine what to do from that point forward, I’m trying to get a sense of how much flexibility there is in the plan to adjust to a 3.0+. Is it really something that’s more like a 2019 event? I just assume a lot of planning goes into the 2018 budget. So changing to a different completion design on the fly in the middle of the year, you might not be able to push it up too much in the back half of the year even if the results continue to look as strong as they have.

Timothy L. Dove: If you look at it, we’re already prosecuting this plan now. So we should be seeing results beginning probably in the second quarter. So you’re exactly right. Once we decide to pull the trigger, let’s say if we were to add more 3.0+ style wells, really in a lot of cases, that involves acquisition of more sand, more water, making sure it’s on time and in place and we have the right horsepower in place. So it could have some effect clearly on the second half results. It’s just that we want to make sure we have a full set of data to make that decision. But you’re exactly right I think when you say what would be the main focus when we seriously ramped up 3.0+? It would be 2019.

Q: Can you add more specifics on the advantage that you’re seeing from sourcing sand from local third-party mines versus expanding your Brady mine, and then what do you also see as the risks around that?

Timothy L. Dove: I think first of all, it’s a little bit early days for us. We have signed our first contract. We’ll be taking deliveries of our first Permian dune sand or Western sand probably in April.

Simply said, the advantages of that are associated with its proximity to the field, and in particular the fact that the relative cost of mining that sand simply because it’s sitting on the ground there is substantially less than mining in the Brady area, where we basically have got to blast the sand and crush it. So it’s just simply a matter of cost on the one hand.

The other thing to note is this is in principle mostly 100-mesh or 40-70-mesh sizes, in other words, relatively small grain sand. So we are in the process right now of testing in various pilot projects the finer mesh sands to make sure that we wouldn’t have any degradation of well results. The current feeling internally is this would not be the case. The 40-70 and 100-mesh will work just as well as some of the coarser grades. But that is something we’ve got to be protective about.

Of course, the thing about it is there’s going to be a lot of mines, it seems like, that are going to be put on production and such that we might have various suppliers that would allow us to then, as was stated earlier, not proceed with the expansion of Brady to the extent that’s a substantial amount of capital we’d rather put into wells. And so I think the main objective is to go through the technical work, make sure that we in fact can lock in low-cost sand. We may be able to reduce our sand cost by 20% by doing this, so there’s a substantial carrot out there for us to prosecute on this point.

Q: And then thinking about the Wolfcamp D, how are we thinking about well cost differences there?

Executive Vice President J.D. Hall: The Wolfcamp D wells are obviously more expensive because we only just recently drilled them. We’re still looking at what the drilling costs are. And of course, as the drilling is more difficult, so are the completions. But the good thing that I can tell you is that in this last run, because we have had so much success in drilling and progressing our drilling, that the Wolfcamp D wells have been a non-issue in regards to drilling. We’ve been able to successfully execute those. But because we’ve only got a benchmark of one, we haven’t really established what that cost looks like. But it’ll just be slightly more expensive than what you would see with the Wolfcamp B well.

Q: Any completion challenges that come with that depth and I assume higher pressure?

Executive Vice President J.D. Hall: Certainly with deeper is more pressure and with that, it does require a little bit more horsepower. And what I can tell you is we successfully deployed the completion on the first well, and we’ll be doing the next three wells here in the next month or so.

We learned a few things on that first one that we’ll be deploying on the second one, but our long-term outlook is that we don’t foresee any challenges associated with those wells. You just work your way through it like we have everything else. And we’ll hit our stride on it shortly, and we see Wolfcamp D being a big part of our program going forward.

Q: You’ve built an extremely valuable asset base here over the last few years and continue to invest in that business going forward. How do you think about the vertical integration of midstream assets within your business model and the ownership of some of the assets, particularly around gas processing, as you progress into 2019 and beyond?

Timothy L. Dove: That’s a great question because we have a wealth of value created by our water business, our gas processing business, our sand business, and our pumping services business, just because of what they allow us to achieve.

But the fact is the reason we do those ourselves is because we want to make sure we have the ability to execute on our plan. And so for the time being, what that means, if you use gas processing as an example, we want to invest in new plants with our partner, Target, to make sure the plants are there on time and ready to take new gas supply, considering gas volumes are considerable in the Permian Basin and growing. And so to the extent we’re an equity owner in that system, we can have a positive influence, we feel like, in dealing with our partner to make sure that we get these plants there in time for our production.

Similarly, in our water business, our water business in the fullness of time, once we have it all fully constructed and sourcing Midland water, will be saving us some $500,000 per well. So at some point in time, we might consider some change of ownership. For the time being, we’re building out the system. We’re making sure we have water as we prosecute our system. Eventually, we may be even further into water sales, as an example. But the fact is we want to build this out and make sure we can execute. At that point in time, we’ll evaluate other alternatives considering the value that we’ve already added.

Anadarko Petroleum (ticker: APC)

Q: In the Delaware, you guys highlighted results from, call it, 30 optimized wells across your portfolio. I wondered, see if we could talk about, this year you have about 160 wells in the Delaware, how many of those would be kind of optimize and what do you see as the growth opportunity for APC once the Reeves and Loving County systems are completed later this year?

Daniel Brown, Executive Vice President: From a 160 well standpoint recognized as we’ve mentioned on multiple occasions, our growth profile in the Delaware Basin is really going to be backend weighted. And so after we get the regional oil treating facilities online, that’s when we’ll see most of our well delivery and most of our production growth. The point of building those regional oil treating facilities is to do exactly what you’re suggesting which is to optimize the facilities that the wells flow through to keep them in an unconstrained manner. So, really a lot of that uplift we saw and there was 30 extended flow back test we — that took place earlier. We’re about optimizing those through those facilities and the results were quite impressive. And so that’s the idea, we’ll get the regional oil treating facilities put together, we’ll flow these wells on constrained. And so most of the wells that we’re delivering into — in 2018 should be in a manner as those ROTFs come online and it’s very, very similar to the playbook we put in place in the DJ and you’ve seen the results there and we expect to replicate them in Delaware Basin.

Q: Curious how you deliberated the choice between the dividend growth and the share buyback. And if there were some sort of yield targeting that you might have considered and that you might consider in the future?

CEO Al Walker: It was not yield targeted. I think if you recall, I know you followed us a couple of years ago, we were at $0.27 a share payable on a quarterly basis when we reduced our share, our dividends at that point. I think taking a back up to the level we did this morning was really an effort to be back in what we feel like as the — a place relative to our peer group that the dividend yield would be competitive. And I was really trying to find a more competitive dividend yield relative to our peers and relative to the growth that our capital efficiency creates that drove that at the end of the day. And Bob I don’t know if you have anything else you like to add to that, you’re certainly welcome to.

CFO Robert Gwin: I think you should expect us to look at both dividends and share repurchases going forward. We certainly look at dividends relative to run rate operations, expected cash flow, expected free cash flow, that is a repeatable cash flow stream that results in a repeatable payment to the shareholder. Whereas, the buybacks are something that we can do somewhat opportunistically either based on larger cash position or asset sales like Alaska that we mentioned or proceeds coming out of the MLP structure as we’ve been talking about.

And I think you should expect, the market should expect we’ll use both going forward. I mean, I think you can look at the buyback yield and a cash yield — and a combined basis I think we have one of the better value propositions out there in terms of the aggregate capital being returned. And quite frankly, I mean, focusing on the debt side is important as well. Obviously, the capital structure matters and buying back part of the company from the debt holders for the benefit of the shareholders is significantly value-add. So I think that’s why we try to articulate it in all three ways, but we knew that one thing we needed to do and it’s a very material increase in the dividend today was to — as Al said, step that dividend back up to the point that it is competitive, and that it is something that is repeatable and predictable for our shareholders, so that it can become more fairly reflected in the share price.

Q: But the mix business model of international, say, for example, Mozambique, Algeria, West Africa, is there any way that you could separate that out and then have just a focus pure-play US unconventional can show that these results are absolutely standalone?

Al Walker: I guess that could be debated. I think our view is that we as an integrated domestic and international company have a fairly attractive asset footprint that throws off with the exception of the Delaware free cash flow from all the other operated properties with Mozambique, as you well know being something that’s on the horizon in the next decade. So I think we do see the free cash flow coming from everywhere other than Delaware is quite attractive and therefore the assets collectively with the emphasis that are placed on capital efficiency being pretty important. And I guess I don’t see the advantage that maybe you do with splitting out domestic and non-domestic assets.

Q: Maybe a question on the DJ Basin. I mean, clearly very strong performance in the fourth quarter, maybe as we look at 2018, I mean, of the 300 wells, how many of them have had the new completion design? And is there anything from the sequential growth that we saw in fourth quarter that was — that was anomalous, not that we should expect 18,000 barrels a day crude growth a quarter in 2018, but is there anything unique about that quarter or does it make the 30% growth rate in 2018, maybe look a little conservative?

Daniel Brown: So this is Danny. With respect to the Nio’s completions going forward, as we mentioned earlier those the completion changes happened on our short and mid-laterals. And so as we look at our mix moving forward both for Codell and long lateral Nio’s, it means about 50% of the completions next year, and DJ will benefit from this new completion design.

We’re looking at how we can apply this toward long laterals within the Nio and in that case that mix will move up to about 70%. But right now as it stands, we’re thinking around 50%, will benefit from the new design, which is something we’re very pleased about. With respect to what we saw in the fourth quarter versus going forward, we mentioned that we are expecting to see 30% year-over-year oil growth in the DJ. I’d say there is not a whole lot anomalous about the fourth quarter, we’re really pleased with the way things are going in, in the DJ Basin and we anticipate delivering that growth as we talked about.

Q: I was very interested in the highlighted technology successes that you discussed and I just want to ask couple of questions about them. First, are these breakthroughs entirely in-house or do they represent some partnership service providers? And if they are in-house, does this shift some spending from service providers into this in-house effort going forward?

Al Walker: Well, I think you probably heard us on many occasions talk about the role of technology, not just at Anadarko, but it relates to the industry. I’m proud to say that what you’re seeing in the information we provided last evening is in fact our own. And therefore I think you should expect that we will continue for quite some time at not only Gen 1, but Gen 2 development. Just to frame it for you, our A group really looks at and it certainly at the forefront of Gen 2, whereas the other technology groups within Anadarko are working on advancing and improving on Gen 1. And so what you’re seeing is a combination of the two.

Q: And then shifting more to the Permian, you talked about the 25% increase in well performance in the Delaware from recent wells. Can you just take us through and give us a little bit more color on how you see the evolution of your Permian Basin well performance and well costs as we move through 2018 specifically as you shift more towards pads and then add some of the technology enhancements?

Daniel Brown: Sure, and this is Danny. From a — I’ll start with well performance. From a well performance perspective, as we mentioned on multiple occasions, we’ve been a bit constrained to date for flowing these wells, which is why we did these extended flowback test to sort to demonstrate to ourselves both from a sizing standpoint and externally that the subsurface capacity is here. And so as we move through and bring the ROTFs online starting mid this year and move forward with the new infrastructure system, we anticipate being able to flow these wells in a much more unconstrained manner, which should lead to much better well performance.

In addition to that, similar to the DJ, we’re taking some of the learnings from there and looking at our completions techniques that we’re using in Delaware Basin. And so it will be a multiple of that, we’ll have more unconstrained infrastructure that we’re flowing into that should allow us to flow higher rate and we’ll see — we should see the benefit of some Gen 2 completion techniques in the Delaware Basin as well. And so more to come on the performance on the Gen 2 completion side, but that’s the plan. So my anticipation is that well performance should be improving in the Delaware Basin as a result of those two things.

From well cost perspective, as you know we’ve been somewhat inefficient and how we’ve developed the field as we’ve gone through operator capture and we’re looking to go more toward pad development. Clearly with the activity that’s going on in the basin currently, there is some pressure for competition for different services. And so there is some inflationary pressure there, but we’ve got the advantage that as we move to a more pad type development that we should see our cost come down as we’re able to build fewer roads, as we’re able to build fewer locations as we’re able to keep crews on locations to reduce mobilizations et cetera. So we actually anticipate our own internal cost coming down, not going up. So for us I think sort of good news on both counts we should see improving well performance and improving well cost in Delaware.


National Oilwell Varco Inc. (ticker: NOV)

Q: You guys make everything, frac spreads, wireline, coiled tubing, rig parts, pipe, mud motors. I’m curious as to the top three tightest products that you see out there right now? In other words, where are you seeing incremental demand greatest? And then just kind of narrow it down to maybe to the top three or so, if you could for us.

Chairman, President and Chief Executive Officer Clay Williams: Downhole drilling motors where we’ve seen them – the greatest pricing gains and, in fact, we’re really back – pretty close to 2014 pricing for those. And that’s helped by the fact we’ve introduced some new technologies for drilling motors that really do well on performance. I would add to that bits, we’re seeing some pretty good demand for some of our ION cutter ReedHycalog bits. That’s really driving a strong, strong demand and I’m looking at Jose, probably in the frac arena certain offerings that we have there.

CFO Jose A. Bayardo: I would say that it’s almost surprising from quarter-to-quarter where we see those positive demand. Obviously, things have been pretty stable on the pressure pumping front, notwithstanding the little bit of a lull that we anticipated in Q4 on the bookings side related to Tier 2 to Tier 4 emissions changes. But, really, prior to this quarter, we saw the big pickup in demand for frac equipment and early in the recovery, we saw much better than anticipated demand for wireline use as well. In this quarter, the story within our – Completion’s capital equipment business land was on the coiled tubing side. So, that’s been a strong performer, certainly this quarter.

Q: from a technology standpoint, I mean, you’ve had quite a few technology-related initiatives during the downturn, and it looks like this innovation is starting to pay off with some particularly strong awards in the most recent quarter. Is there a large margin upside from this technology uplift? Is this something that you could potentially quantify? And when would you expect to begin to benefit and see this flow through the income statement?

Clay Williams: Yeah, we have had great strides and success across a number of areas. Unfortunately, introduce new products and new technology, and inevitably they’re going to be a negative margin for a while until they get traction in the marketplace. And so depending on what specific products we’re talking about and kind of where they are in their launch process, those may or may not be contributing

meaningfully yet. But what’s interesting to me is sort of this portfolio now that NOV brings to the oilfield, trying to look to see where the puck is going and positioning ourselves to provide the technologies to get there. And so I’m really excited about kind of the trajectory that we’re on and the success that we’ve had so far. To be fair, not a big contributor of EBITDA so far, but really laying the foundation for what NOV looks like in the future. And to me, that’s very, very exciting.

Q: So I think what I’m trying to understand a little bit more here is in the past you talk about a decrease in the amount of drill pipe inventories in stock, the prospect of that business to pick up. I was wondering if I missed some of this that you might’ve mentioned a little bit earlier, I apologize, you guys do go through this stuff pretty quickly, but can you just mention drill pipe and then maybe elaborate a little bit more on what’s going on with the intelligent drill pipe?

Clay Williams: We also introduced a new premium thread connection in 2017 called the Delta connection which is really specifically focused on land drilling contractors and has a lower total cost of ownership and is a little more durable for land operations, and that’s starting to get really good traction and I think that will help fuel demand. And then finally, I think you asked about Wired Drill Pipe and that’s – the ability – traditionally, MWD mud pulse systems operate at 5 or 10 or maybe 15 bits per second; Wired Drill Pipe operates at 55,000 bits per second, and so it is truly a much, much, much greater bandwidth. And what oil and gas customers are realizing is that the ability to get a lot more data from the bottom of the hole, which IntelliServ offers them, is opening up new sorts of drilling techniques and better insight into downhole conditions and enables them to avoid lots of trouble, costs, and to drill faster and to evaluate formations on the fly much better. So it’s just all the way around a really, really promising technology. And the good news for us, I think we’ve got enough experience in our belt where it’s fairly, fairly bulletproof operationally. It’s reliable and does a great job, and we’re sort of seeing this blossoming of data measurements downhole that utilize that bandwidth and to improve operations. And so that’s what’s driving demand for the IntelliServ Drill Pipe.

Q: And do you think, Clay, you’re at a point now where you’re going to see much more mass adoption?

Clay Williams: I think so. It’s still single-digit number of jobs that we have going on simultaneously out there, but double digits numbers of customers that are expressing interest, and really not just kicking tires but kind of getting in line to put it to work. So what’s also interesting to me, it’s not one sort of one operational challenge or one issue that this is being employed to fix. It’s a broad, a pretty wide number of downhole measurements that are being made and downhole conditions and challenges that it’s being applied to and applied to successfully. So I’m really pretty jazzed about where this is going. And it’s not hard for me to imagine some number of years out where this becomes a much more standard piece of the kit on a lot of drilling operations around the world.

Hess Corp. (ticker: HES)

Q: I guess, if you could talk maybe a little bit here, your performance in the Bakken, six rigs is going to deliver growth up to the 175 level by 2021, how much more improvement in well performance is factored in on that?

CEO John Hess: As we said in our opening remarks, our new completion design, which is the 60-stage, 140,000 pounds per stage, has resulted in a 10% to 15% uplift in EUR and also IP 180 rates, that 175 at six rigs reflects improvement from that move to that new completion design.

Q: If you look across the rest of the portfolio, are you happy with the current side of the portfolio, would you consider selling any of the Asian assets or are you in a position, where you could consider to farming down Guyana at all or is there still too much undiscovered resource at this point?

John Hess: Obviously we’ve been pretty active optimizing our portfolio. We have an open mind. We’re always there to maximize value. We have a long-term strategy in portfolio that we and the Board worked on to have the cash generators, along with the growth engines in Guyana and the Bakken. So we will always have an open mind to maximize value, as we’ve shown in the past.

Having said that, the major focus of the Company is to capitalize on the amazing investment opportunity we have in the Guyana and the Bakken. And to do that we got to have a strong balance sheet and cash. We don’t have a funding deficit, we pre-fund it and as Guyana gets bigger and better with FPSO 2 now being defined and FPSO 3 and by the way a pretty active exploration and appraisal program, we got to make sure we have the cash for that.

So, our focus is much more on Guyana and in funding the world-class investment opportunity and high financial returns there. To sell part of that would not be the right thing for our shareholders, because that is probably the best investment return certainly in Hess’ portfolio and one of the best in the industry. And if we could get more of it, we would, but selling it would be a wrong thing to do.

Q: A few weeks ago, the fiscal terms of the Guyana Production Sharing Agreement were published. And I suppose, for those investors who might look at that and say, how can a deepwater project have a breakeven oil price below $40 a barrel? What are the key attributes of those fiscal terms that are contributing to that low break-even?

John Hess: it’s really all the attributes and you have to not even just the fiscal terms, it’s — so let me just start with Guyana overall. So our Liza find that we have the geology, the reservoirs are just fantastic, the permeability is fantastic, the size, obviously, you’ve seen the scale. So that plays into getting that low break-even. The next thing as you compare what you see the other basins around the world, the depths that you drill to in Guyana are much shallower and the other thing is there is no salt. So from an imaging standpoint that helps. And then there’s less casing strings. So the exploration wells and the development wells obviously just cost less. I mean clearly, as you would compare let’s say to like a Gulf of Mexico type aspect.

We’re also in the low point in the cycle from offshore. So again, yards are looking for work, rigs are looking for work. So all the costs that Exxon is getting for our developments are you’re just hitting this obviously at the right point in the cycle. And then it’s just a blend of the fiscal terms. So you have a production sharing contract. So what makes just start with any production sharing contract, it gives you downside protection, that’s what it set up for to encourage investment from oil company. So as oil prices go lower, you get more barrels because you get the cost recover from that standpoint. So again, as prices go down and given you that break-even, you get that production sharing cost impact. And then the terms are out there. They’re on the government website for people to see and that along with just the unique attributes of the Guyana’s basin in general allow you to get this really low break-even cost.

Q: Just two quick ones on Guyana. When we were out in December, John, you had mentioned or Greg had mentioned that possibly would buy the FPSO for Liza 2. Is that still the case? And then the other question is on Ranger. It took longer to reach TD in a carbonate well. Obviously, it was a cautious drill, but how much faster you think the drilling would be for carbonate play?

John Hess: Well, let me answer the Ranger question first. Yes, it was a very cautious drill. John, as you know, carbonates can be very tricky, but we didn’t discover any of the downsides in the drilling of this well that potentially could have been there. So, I think certainly on the next appraisal well of Ranger, we anticipate the drilling time will improve and the cost will be lower obviously.

Regarding the boat on Phase 2, that decision has not been made, but certainly from a — from a financial standpoint, it’s better to purchase these things ultimately just so you don’t have to pay the uplift on lease cost, right. So I think we’re aligned with the operator that ultimately you’d want to purchase these things but that decision has not been made.


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