馬拉松石油 (MRO) 2017 Q2 法說會逐字稿

Welcome to the Marathon Oil Corporation 2017 Second Quarter Earnings Conference Call. My name is Paulette, and I will be your operator for today's call. (Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Zach Dailey. You may begin.

Thanks, Paulette. Good morning, everyone, and thanks for joining us today. Welcome to Marathon Oil's Second Quarter 2017 Conference Call. I'm Zach Dailey, Vice President of Investor Relations. Also joining me this morning are Lee Tillman, President and CEO; Mitch Little, Executive Vice President of Operations; Dane Whitehead, Executive Vice President and CFO; and Tom Hellman, Regional Vice President of the Permian.

Last night, in connection with our earnings release, we also released prepared remarks and associated slides, which can be found on our website at marathonoil.com. Following some brief remarks from Lee, we'll open the call up for Q&A, where we request that you ask no more than two questions, and you can re-prompt as time permits.

As a reminder, today's call may contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. Please read the disclosures in our earnings release and in our SEC filings for a discussion of these items. Reconciliations of any non-GAAP financial measures we discussed can be found in the quarterly information package on our website.

With that, I'll turn the call over to Lee.

Thanks, Zach. Good morning, and thank you for joining us today. I will share just a few opening comments, and then we'll spend the bulk of our time together addressing your questions.

We remain in a dynamic pricing environment that continues to create uncertainty in our forward outlook on the commodity. This isn't something new or different and has certainly been an ever-present feature for the last few years. Our view is that while supply and demand continue to come into balance, the storage overhang has been more stubborn than initially expected, and despite recent draws, it remains a key proof point for more stability. Additionally, there remains uncertainty in OPEC's discipline and longer-term response as well as geopolitical tensions in places such as Venezuela and Nigeria.

But while we don't pretend to predict pricing, we want to prepare our business to be successful across a broad range and a more moderate range of pricing. That preparation includes the strength of our balance sheet, a low-cost structure, a relentless focus on execution excellence, maintaining flexibility and agility in our capital allocation and an ongoing commitment to portfolio simplification and concentration. All of this is designed to deliver long-term value and returns to our shareholders. There's little doubt that the current environment tests all this preparation and underscores financial discipline, but we are well equipped.

In the second quarter, we achieved outstanding operational performance across the portfolio. We delivered on our commitment to resume sequential production growth in the resource plays, with resource play growth of 6% and overall company growth of 6% excluding Libya, which has continued to ramp up production. Our U.S. production of 222,000 BOE per day exceeded the top end of our guidance, and our international business exceeded the midpoint of guidance at 127,000 BOE per day.

At a basin level, Oklahoma grew 11% sequentially while maintaining their focus on the strategic objectives of leasehold, delineation and infill spacing pilots. Eagle Ford was up sequentially due to outstanding well performance and continued gains and efficiency while also improving results in the oil window farther west. We've returned the Bakken to sequential growth and delivered impressive results from our first 2 Hector wells with advanced completions, signaling a successful start to elevating the returns in this 120,000 net acre area.

And in the Northern Delaware, we've built a world-class asset team, ramped to 3 rigs, brought on our first MRO designed completion job and are driving to optimize the plan of development. Our program in the second half of the year is designed to feed that effort. We're also very pleased to be joined today by our Permian regional Vice President, Tom Hellman.

We began 2017 with some key questions, some key uncertainties embedded into the assumptions that formed our capital program: an Oklahoma program that was heavily weighted towards delineation, leasehold and infill spacing; a Bakken program seeking to test the response of the Hector area to high-intensity completions; an Eagle Ford program driving for the next level of efficiency while looking to enhance the performance of the oil window farther west; and finally, the integration of a newly acquired acreage position in the Northern Delaware. And of course, one of our biggest assumptions was the expected pricing of WTI, which we placed originally at $55.

We now have more clarity. So with just over half the year behind us, the material progress we've made against our strategic objectives, coupled with our asset teams exceeding initial expectations on efficiency, base performance and new well productivity, have enhanced our production outlook for the remainder of the year. You should expect our capital allocation to remain a dynamic, real-time effort as we continually optimize across our 4 basins, leverage learnings and respond to performance trends as well as the macro environment. Our drive for maximizing returns is neither static nor limited to an annual budget cycle.

Our plans in the second half of 2017 have us bringing 20% more wells to sales than in the first half of the year. For the resource plays, Eagle Ford's efficiency and productivity improvements have us on track to hold production flat sequentially from second quarter levels, which is better than we'd expected. And Northern Delaware has successfully ramped to its 3-rig objective, which will be steady throughout the remainder of the year. We've taken the opportunity to optimize both the Bakken and Oklahoma programs to better reflect the strongly positive outcomes and insights that we have gained from the first half of the year. These include improvements in new well productivity, better-than-expected carry-in performance from 2016 wells, infill resequencing to provide longer-term production history that enhances our learning opportunities between pilots, and proactive steps to correct some of the inefficiencies we observed in the very steep activity increase for both basins.

As a result of all this progress, we are increasing both our full year total company production guidance and our resource play exit rate guidance while lowering full year CapEx by about 10%. We are raising the midpoint of our full year total company production growth guidance, adjusted for divestitures, to 7%. Similarly, our exit-to-exit rate guidance for the resource plays will move from 20-25%, to 23-27%. With the confidence that we will meet our strategic objectives and exceed our original volumes growth commitments, we can limit 2017 outspend and remain well positioned to maintain operational momentum into 2018.

Commodity pricing being equal, our view is that the second half of 2017 represents a transient, somewhat high watermark for outspend as CapEx is a bit out of phase with the operating cash flows it ultimately generates. And though we are just beginning to work our 2018 business plan, our capital allocation priorities remain the same. The strategic objectives of leasehold, delineation and infill pilots for the STACK and Northern Delaware, followed by allocation to the highest risk-adjusted returns in the Eagle Ford, Bakken and SCOOP.

As a result of the 2017 exit rate momentum, we will carry a larger higher-margin production base into 2018, with the resource plays expected to account for a more significant proportion of the total production mix. This shift delivers stronger operating cash flow and underpins our goal to deliver growth consistent with our 2017 to 2021 benchmark CAGRs within cash flows with WTI in the low $50s.

We continue to make considerable progress with portfolio management. In the second quarter, we closed on the sale of our Canadian Oil Sands business and both of our Northern Delaware acquisitions. With these strong moves, we clearly established our differentiated position in 4 of the lowest-cost, liquid-rich U.S. resource basins.

And on the balance sheet, our successful debt offering pushed our next debt maturity out to 2020, reduced interest expense by about $60 million and, coupled with cash on hand, reduced gross debt by about $750 million. We ended the second quarter with $2.6 billion of cash, up from the previous quarter, and liquidity of almost $6 billion, supported by an untapped revolver that was recently extended and upsized.

Our actions are and will be tempered by the uncertainty of the macro, but are underpinned by our confidence in our balance sheet, the quality and scale of our resource, our flexibility in capital allocation and our demonstrated continuous improvement in efficiency and productivity. At the heart of it all are our dedicated employees whose commitment and innovation has only been sharpened by these dynamic times.

Thank you. And with that, I'll hand it back to the operator to begin the Q&A.

(Operator Instructions) And our first question comes from Ryan Todd from Deutsche Bank.

Maybe if I could start off with capital and cash flows. I mean, you've largely covered cash outflows within operating cash flow in the first half. How do you think about balancing spend into 2018? How much would you be willing to outspend in 2018 if oil prices were lower, $40 or $45? And if you reduced activity, where would the reductions likely take place?

Well, let me start off, Ryan, by saying our objective -- and we're still in the early days, obviously, of thinking about 2018, but we remain resolute in our objective of living within cash flows into 2018. As I mentioned, when we look at our benchmark, kind of 2017 to 2021 CAGR case, we're able to deliver those growth rates now in the very low $50s kind of WTI levels. However, if we need additional flexibility or adjustability, we have ample tools available to us to adjust to what the macro does deliver.

Okay. So generally, target is spending within cash flow but a little bit of flexibility to swing either way depending on the situation. Is that how we should think about it?

Absolutely. We're -- obviously, we're not here today to talk about the 2018 budget. But as we think about it more in conceptual terms, we still believe we have the right model to deliver profitable, competitive growth and do that within cash flows at a relatively moderate WTI pricing.

Great. That's helpful. And then maybe, in the Bakken, you had a couple of really strong wells in the Hector area with enhanced completions there. I mean, what does that mean for the 115,000 acres in the Hector area? And what are your plans for future activity from here?

Yes, sure. Ryan, this is Mitch. As you note, we brought on our first 2 Hector wells with our enhanced completion design that we had kind of proven up in the Myrmidon area. This year, one of our objectives was to extend that down into Hector. Those first 2 wells have come on strong. I think average IP between the 2 is about 2,500 BOE a day. And we've got a number of additional trials as we'd laid out in the earnings release. We're going to extend that across the rest of Hector, moving from kind of northwest to the east. We've got an additional 5 pilots, and about 1/3 of our remaining wells to sales in the second half will come from Hector. We do see some variability in reservoir quality across that Hector position, and so the objectives of the additional wells this year will be to see just how far we can extend that. But obviously, we're very encouraged by the early results.

Our next question comes from Guy Baber from Simmons.

Lee, I'm just trying to better understand the improving cash flow profile and overall, just resilience of the portfolio, how that's evolved. Given well productivity, capital efficiency of the business is consistently improving. But how should we think of the framework in terms of the evolution and the view of the business in terms of the amount of capital that maybe your portfolio needs, especially in the U.S. resource plays, to hold that level of production relatively flattish?

Yes. Guy, well, I think you're hitting on some things that we really did learn in the first half of the year. We did truly outperform against our initial expectations, and we did it across really all 3 of those key areas, which is efficiency; new well productivity; as well as just the base performance, our base business, really the carry-in from 2016. So we learned a lot in the first half of the year. As we take those learnings, we've obviously built those in and integrated that into the second half of the year plan. And as we move forward, looking at 2018, we'll obviously take not only first half but second half year results and integrate that as well. All of those things, though, will contribute to continuing to drive our overall enterprise-level kind of, if you will, breakeven costs down. And consequently, if we were to look at a case where we wanted to hold resource play production flat to, say, our exit rate out of this year, we know that, that number is going to be well south of $2 billion. And we're still obviously working on the plans, but we know that our portfolio today is more robust than it ever has been.

That's very, very helpful. And then I just wanted to -- you've covered this somewhat, but just wanted to talk a little bit more specifically about the reduction in the capital spending guidance. But if you could just talk about kind of how you made the decision to go ahead and reduce the guidance and maybe where specifically you're seeing those efficiencies on that efficiency front, like specifically outperforming relative to the internal plan. It seems pretty broad-based across the portfolio, but on the CapEx front, I'd be curious of your comments there.

Yes. Well, obviously, the ability to reduce capital while not only holding to our volume commitments but actually increasing them is a function of the fact that we've simply outperformed in the first half of the year, and that's given us more confidence that we essentially can do more with less. Coupled with that, though, we also wanted to make sure that we achieved our strategic objectives. We talked about one of those already, which was the Hector program, making sure that we had adequate capital to fully test and vet that Hector area. Similarly, in the Eagle Ford, for instance, we had a strategic objective of pushing a bit farther to the west in the oil window. Not dissimilar and obviously, in Oklahoma, it was key for us to not only keep doing our leasehold and delineation but also to continue with the infill spacing pilots. So we had to not only deliver the volumes, but we also had to deliver against those strategic objectives. So when I think about the second half of the year, it was really colored and influenced by all of those results from the first half of the year. And we certainly wanted to also consider the fact that we did not want to be tone deaf to the macro and the impact that, that would have on the balance sheet as well. At a basin level, Eagle Ford and Bakken are clearly in development mode. That's where we obviously see some of the highest efficiency and highest returns being generated. And my compliments to both of those teams. And you're seeing it not only on well productivity, in other words, what the wells deliver, but also on well cost. And we're largely seeing that despite the fact that we were in a very, I would say, inflationary period at the beginning of this year. So my compliments to those teams because it just shows the power of, when you can get into development mode, just the amount of capital efficiency and the level of returns that you can drive there.

Our next question comes from Doug Leggate from Bank of America.

I wonder if I could ask a couple of questions. Can you hear me okay?

Yes. I've got you, Doug. Go ahead.

So Lee, I wonder if you could talk more -- a little more on the Bakken and really more in the context of your guidance. Your type curves, I think -- I feel like I ask you this question every quarter, but your type curves are clearly dated relative to the stellar results that you have. What's holding you back from updating what you really think is going on there? And if I could just add a bolt-on to that. The implications of the de-risked inventory in the Hector, if you could help us with that. I know it's only 2 wells, but I guess you've got 5 more in the second half that might help with that. But any color on those 2 aspects? And I've got a quick follow-up, please.

Yes. Well, certainly, on the Bakken area, we continue to be very encouraged from the results there. And what we tried to do, Doug, was to provide that extended production history for both East and West Myrmidon dating all the way back to really the Doll Pad in 2015 such that -- the dataset was there. It was visible. We have shown it relative to kind of our more historic, if you will, type curve. But clearly, the performance is trending above that. We still have development work to do there, but our goal was to provide enough information where folks, again, could look at the real data and draw their own conclusions from it. In due course, we'll make adjustments to type curves when we feel that's appropriate to do so, but we feel very good about the data that we're providing and the visibility that we're providing in the market on the Bakken performance. Similarly, I think, on the Hector side, I think, as Mitch stated, we started kind of in that northwest area. We've got only 2 wells thus far that we've brought to sales. It looks really good initially, but we do need to step across the geology there and make sure that we're going to be able to extend that to the full acreage position. And with about 1/3 of our program this year going to Hector, that's exactly our intent, is to really push that boundary over and make sure that we can extend that to as much of that 120,000 acres as possible.

Maybe I'll take my follow-up.

Doug, just...

Go ahead. Please, go ahead.

If I could, just to clarify, to make sure it's clear, there's 5 additional pads in Hector, not 5 additional wells. So it's about 1/3 of the wells to sales in the second half.

Yes, good point. Thanks, Mitch.

That's helpful. Maybe I'll take my follow-up. This is a point of clarification. And I guess -- I mean, obviously, you've now completely transformed this portfolio. But the guidance you gave, I guess, a year or 2 ago, the 10% to 12% at $55, now coming down into the $50s, I just want to be clear. What are you assuming in the type curves for that guidance? Is it the dated type curve? Or is it the current well performance? I'm Just trying to get a handle on where the risk -- the upside risk, I guess, is to how you're guiding us on what you can do at $50 oil.

Sure. Obviously, internally, Doug, we're going to take our best risk view of the current production data and incorporate that into our forward outlook. But it is still going to be a risk view based on our confidence level in the dataset that we have currently. So we'll be running with the most up-to-date but risk-adjusted data in our kind of longer-term guidance that we provided in the market. And we're clearly going through the planning process today, and we'll take new data into that process not only for 2018 but for the long-term view as well.

Our next question comes from Evan Calio from Morgan Stanley.

You raised your production guidance, as noted, while reducing CapEx and the number of completions versus your original 2017 plan. I mean, have you guys lowered rig or well count production? Or are you still ramping to 25? And on the budgeting comment, if you had to reduce activity to stay closer to cash flow, given your strategic portfolio objectives, where would that be?

Yes. First of all, I guess, on your cash flow question, I think you need to consider the fact that we really began the year with a view that we were going to have a level of outspend this year that was kind of part and parcel of our plan. I think the positive is, is that we built that plan on a $55 deck. We're now, of course, in a more of an upper $40, lower $50 kind of world, and we feel like we can still deliver and limit our outspend amount to, say, $200 million to $300 million this year. So that was all part of the plan. With the lost of OSM cash flows and, obviously, with the new investment in Northern Delaware, that was part of our original plan. When we think about Delaware activity levels, we tend to look at the metric which is the best measure of output, which is wells to sales. Rigs, we're going to optimize. Frac crews, we're going to optimize. We continue to gain efficiencies across both of those areas of our business. So we really look at wells to sales. And in an absolute sense, we're going to have 20% more wells to sales in the second half of the year. When we look at kind of a basin level, we're going to be running Eagle Ford at a pace and a cadence that will hold that production relatively flat to 2Q. In the Bakken, we want to deliver the Myrmidon program but also continue with the work in Hector, and so we'll optimize the program around that. And the Bakken, of course, well count, wells to sales will be much greater in the second half of the year than it was in the first half of the year as we ramped up there. In Northern Delaware, we're really on a 3-rig run rate there because of the work that we're doing to really define the plan of development. And then finally in Oklahoma, with the outperformance and our ability to progress our strategic objectives, now we want to make sure that the cadence really fits in terms of the pace of driving our infill programs such that we have the opportunity to incorporate learnings in real time. And so it's those factors really that are driving our wells to sales, if you will, in the second half of the year. So we think of it more as a wells to sales story versus a rig count story.

Yes. No, that's how we model it. I appreciate that color. My second question, I think positive results on Hector was covered, and congrats there. But on the Hansens infill wells, which IP-ed 35% to 30% below the parent of the same section and there was a similar drop-off, parent to child, at Yost. To what extent is Hansens' performance representative of what we should expect in the black oil development -- or black oil window under full development? And what can you do to mitigate the drop-off in performance from parent to child and what we might see later this year in Eve?

Yes. I'm going to start, and then I'm going to hand over to Mitch for a little bit more of the technical details. First and foremost, to me, the Hansens continues to support kind of our 6-well per DSU base case that we had for the black oil window. But I will stress it is still a very limited dataset. Hansens is only 1 of 3 or 4 infills in the Meramec black oil window. So we're still testing a lot of variables. I mean these truly are pilots. These are not development pads. These are truly pilots where we're still trying to understand the best way to maximize value and return from each of these DSUs. And I want to stress value and return because it's very easy, I think, to get distracted by just the IP30 game. And you have to look at the well productivity, the completed well cost and how that's actually delivering returns and value. And I think, oftentimes, we try to kind of take the STACK as being this ubiquitous play that's the same everywhere, where we know that we've got a volatile oil window, we've got the black oil window. They're very different. Their cost structures are very different. And consequently, their IP performance is quite different. So we're still very early days. I think we've got 2 of our pilots now in the ground, but we continue to be obviously supportive of where the black oil Meramec program is going to take us, but it's still very early days. With that, Mitch?

Yes. Evan, I'll just try to build on to that a little bit. And maybe starting -- picking up from one of Lee's last points, which -- the Hansens section, those were 4,600-foot laterals, completed well cost of about $4.3 million. And so as Lee rightly points out, that's not a ubiquitous play. There's different drilling depths and different completion styles and techniques across the play. These are unique plays, not unlike any other play. And if you look at the progression of whether it's Cana Woodford or Bakken or Eagle Ford, we're in the optimization phase. And the fact pattern that we see here in the number of trials that's going on is pretty consistent with how those plays built up, and ultimately, we cracked the nut. These are the kind of technical challenges that our teams love to solve. And they've done it before, and I've got confidence that we'll continue to optimize here with a lot of running room. To specifically answer one of your other questions, the Yost was our first attempt in the black oil infill. We started with kind of our baseline completion design there. We've learned some things about well interactions, and we've modified completion parameters on the Hansens in terms of fluid chemistry, fluid mix and the use of diversion. We're encouraged -- and not to mention, tighter spacing tests. If you recall and as we tried to lay out in the slides, this was really a multidimensional pilot, and on the western side of the section, we actually tested 660-foot spacing versus about 900-foot spacing on the Yost. With the completion changes we made, even on the tighter spacing, we're seeing some uplift in the early performance. We're encouraged by that. We invested a lot in technical data acquisition in the Hansens to help us better characterize the fracture geometry through use of electromagnetic proppant, microseismic and Seismos, which is a pulse wave imaging log. So now we're integrating that with the performance of these wells. We'll make some more radical design changes in the next pads, which we think will help concentrate the energy closer to the new wells, and we look forward to seeing how quickly and how materially we can optimize as we go forward, particularly, these direct offset wells.

And so there'll be some direct changes in the Eve in the back half of this year?

Absolutely.

And Evan, that's part of the reason why cadence right now is very important, because we want to make sure that we have time to integrate and incorporate this substantial data acquisition and technical work that we're doing in subsequent pads. And so that's the phase that we're in right now, and so that does really set some of that cadence in Oklahoma at least as it pertains to infill spacing in the black oil window.

Our next question comes from Paul Sankey from Wolfe Research.

The call, I guess rightly, has all been about the U.S. I was wondering if there's potential for you, Lee, to go back to the restructuring and focusing strategy that you previously employed to get you where you are today. Obviously, what I'm thinking about is the disposal of international. And I do think you'll get rewarded for even more focus. And sort of a follow-up would be, can you talk about how dividend and dividend growth fits into this? Because, again, the way the company is moving suggests that it will be more about growth and resource development than it would be about, for example, a strategy to have a rapidly rising dividend? I think we would favor the latter but we'd all like your latest views.

Okay. Thanks for expressing a preference, Paul. Well, let me start with portfolio management. We will never be done with portfolio management. It's just something that we need to do as an E&P company. We've had a very strong focus on that. Our corporate development team has just done an outstanding job in implementing our noncore asset program, which really culminated in some ways with the exit from the Oil Sands Mining business. But I would not want anyone to think, with that transaction, that we consider ourselves done. There are still elements of our portfolio that we continue to assess that are outside of kind of our core assets, which are really our U.S. resource plays and Equatorial Guinea, are 2 -- are really the 2 areas where -- that really comprise our core business today. But we continue to look for avenues to continue to improve that simplification and concentration of our portfolio. So I would just say continue to watch that space, Paul. I mean, we simply will never be done on the portfolio optimization side. EG today provides a very key free cash flow business that supports our ability to deliver within our kind of cash flow-neutral objectives, so it still fulfills a very key role for us. But as you step outside of those assets, we want to continue to challenge and ask ourselves the question: Do they compete for capital allocation? And could they potentially have more value to another operator? On your second question around dividend growth and the dividend in general, the dividend discussion is a discussion we have each and every quarter as a leadership team and then subsequently with our board as well. We scrutinize that, make sure that it still fits for where we are in the business cycle and where we are as a company today, and we talk about how that might be used in the future as we get to a different future state. But it's something that's always under discussion. At this stage and I think as we really continue to demonstrate consistent and profitable growth quarter in and quarter out, we believe that the dividend is still playing a role to help us scrutinize that last dollar of capital, to ensure that we can put it to good use on behalf of the shareholder. But rest assured, it is a discussion each and every quarter with leadership.

Yes. And I think, as you said, I did express a preference, but I'm not 100% convinced as long as you're doing what you say you're doing, which is profitably growing, I guess, at least adding to resource.

Yes. Thank you, Paul. Appreciate it.

Our next question comes from Pavel Molchanov from Raymond James.

One of the issues in the industry right now is the oil-gas production mix. And one of the striking things in your guidance is you're saying your BOE will be growing in line with your liquids numbers. Given that gas is back below the $3 level, is there a sense that maybe you should be kind of de-emphasizing the gas component of your activity?

Well, I think, right now, we are prioritizing, obviously, on the most profitable wells that we can bring to sales. For us, because of the portfolio, and our 4 basins is largely liquids-biased, with the exception maybe of some of the gas in the SCOOP area, most of the gas production you're seeing from us is associated gas outside of our international business, where you have EG. But we like our oil and liquids weighting. We felt it was very important to be specific that our growth metrics from both a BOE as well as an oil basis, to give that clarity on that mix going forward. But that's a mix that's going, in our view, to continue to stay strong. We like our liquids bias, and we're going to continue to support that liquids and oil bias.

Okay. And then I look at your hedge book. You've hedged out a pretty decent amount, maybe 30% or so of your domestic oil production in the second half of this year. It kind of tapers off into 2018. Are you looking to add more hedges, particularly as the curve kind of gets back into contango?

Pavel, this is Dane. Yes, you may have seen in our disclosure and our slide deck that we recently added about 20,000 barrels a day of Cal18 3-way oil positions at $43 by $50 by $55. And we certainly are going to keep methodically working our risk management activities, both in the balance of the '17 and '18. And as we go forward, we'll start looking into '19 as well. I think we have a well-established team and set of practices now. And when we see market opportunities created by rallies, particularly in oil but we watch gas and NGLs as well, expect us to continue to leg into those positions.

I think we are going to be a defensive hedger, where we try to get in there and protect the key aspects of our investment program. But at the same time, going back to my comments around our liquids weighting, we want to absolutely make sure that we preserve that upside potential for our investors as well. That's critically important to our go-forward business model.

(Operator Instructions) Our next question comes from Jeffrey Campbell from Tuohy Brothers.

Lee, on Slide 14, I was impressed that Marathon is already conducting an ambitious Delaware Basin spacing and delineation test in Cypress, but I wanted to point out the difference between the illustration and the description. The description says testing spacing in the X-Y in the upper Wolfcamp and delineation in the middle Wolfcamp and the third Bone Spring. But the illustration additionally shows new wells in the second Bone Spring. So I was just wondering if you could add some color on -- to how the second Bone Spring fits into your overall Cypress thought process.

Jeffrey, this is Tom. Yes, nice catch there. Early days, right after even the acquisition, even with the BD team intact, we were already talking about this infill pilot. And right away, we looked at that XY / A for a practical well spacing of 8 wells a section. And we're going to add some science to this, and we're going to be very aggressive on the completions. And while we are working that, we also recognize that the second Bone above that looks great as well, and we wanted to add some more wells in the area. So that's a 4-well per section, basically, spacing trial above it. It actually adds a little more logistics and just scale to this. So we're also testing a logistics and learning curve on the drilling and the completion side because we went off and we have a dedicated crew now that will come in and do that on the frac side with much better pricing. We've even self-sourced our own sand for that. So all of that came into, yes, the test itself, that infill well spacing, and we're also going to pick up a third Bone well and a lower Wolfcamp, as you can see, for some delineation.

And kind of staying on the theme of delineation and multiple well -- multiple zone potential. Also on the Permian Basin, also on the Delaware basin, many producers are moving towards a model of completing all the locations of a given zone or even several zones at once to avoid well interference and enhance efficiencies. I was wondering if you're going to be testing any of those kind of concepts with this pilot and maybe others that you'll do. And also, I was wondering if you think that, that is or is not appropriate, for OK, the Oklahoma resource.

Yes. I think that -- this is Lee, Jeff. I think that, clearly, we are watching those developments very closely, as you know, particularly in the Midland, where that work seems to be progressing much more aggressively. I mean, Northern Delaware still is kind of in the early, early phases. This is really our first foray in getting out and testing some of our assumptions we had built into the acquisition economic. I think, though, when you go to those extremely large-scale developments, you need to have a pretty high certainty on your spacing and your completion designs and, ultimately, how you're going to manage the peak production that's going to come with that. We're not at that phase. I mean, we pick -- we just completed 2 wells in the last quarter. This was really an acreage pickup by us. We are still, I would say, assessing and determining the best combination of spacing, both vertically and horizontally, as well as the completion design that complements that spacing. And so to go out and start replicating that and more of a manufacturing mode, we're not quite there yet. So that's kind of the technical reason. I think pragmatically, you've got to be extremely comfortable that the capital efficiency that you're generating at the surface is consistent maybe with some of the subsurface risks that you may be taking on with that because you really do have to standardize on a design and replicate a design and have confidence in that design, both spacing and completions, to do that type of initial large-scale development. Longer term, I think, at the end of the day, we're going to have to be able to understand though and manage well communication, whether we do it in large developments or small developments. This is part of the physics that we ultimately are going to have to understand and be able to account for and plan for.

No, I appreciate that color, and I think that makes perfect sense. Just to follow that up again, are you -- is this kind of thing appropriate for Oklahoma resource, particularly thinking of the Hansens pilot and the other pilots you're doing? Or is there something unique in Oklahoma that is not going to make this kind of manufacturing model ever really viable?

Well, I think that you could apply a similar kind of logic, I think, in Oklahoma. I think in Oklahoma, there's a bit more development there. You have a bit more leasehold offsets to you as well. So perhaps a pure kind of application with absolutely no other well interference might be a bit more challenging just because of the layout of Oklahoma. But I do think that these are all things that we need to consider as we move through our own pilot programs. Is -- are there some implicit advantages, even if you have a parent well in place, to going in and doing your, if you will, full development pattern all at one time? Obviously, coming back at a later point presents some unique challenges. So I think the logic can certainly be applied in Oklahoma.

And we're showing no further questions. I will now to turn the call back to Lee Tillman for closing remarks.

All right. Well, thank you very much for joining us today. It was a fantastic quarter. I want to again thank all of our teams, our employees that contributed to this great outcome. We continue to believe that the robust model that we've developed, with a focus on these U.S. unconventional plays to deliver long-term profitable growth, do that within cash flows to generate value for our shareholders is a very compelling investment case. So thank you for your time and attention today and your interest in Marathon Oil.

Ladies and gentlemen, this concludes today's conference. Thank you for participating, and you may now disconnect.