馬拉松石油 (MRO) 2018 Q1 法說會逐字稿

Welcome to the MRO First Quarter 2018 Earnings Conference Call. My name is Hilda, and I will be your operator for today. (Operator Instructions) Please note that this conference is being recorded. I will now turn the call over to Mr. Zach Dailey. Mr. Dailey, you may begin.

Thanks, and good morning. Last night, we issued a press release, slide presentation and investor packet that address our first quarter results. These documents can be found on our website at marathonoil.com. Today's call will 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. I refer everyone to the cautionary language included in the press release and presentation materials as well as to the risk factors described in our SEC filings.

With that, I'll turn the call over to Lee Tillman, our President and CEO, who will provide a few opening remarks before we open the call to Q&A.

Thanks, Zach, and thank you to everyone joining us this morning.

After a pivotal 2017, 2018 is off to a great start and has continued our returns-focused momentum with our development capital program on track to deliver over 65% annual improvement and corporate cash returns at strip pricing. Our differentiated multi-basin model delivered strong 9% sequential U.S. oil growth. And our asset-level execution underpinned our confidence to raise our full year 2018 resource play guidance, while also steering to the upper end of our total company guidance, all of this with our $2.3 billion development capital budget unchanged. An important point to note is that our first quarter development CapEx is not ratable, due primarily to some higher working interest relative to the remainder of 2018 and other timing effects.

Highlights for the quarter were numerous, but I'd like to underscore just a few. We continue to expand the core of our Bakken and Eagle Ford positions through enhanced well performance in the Hector area and Atascosa County, respectively, uplifting economics and inventory quality while generating significant free cash flow from both assets. Bakken grew production 7% sequentially and continued its basin-leading performance setting new 30-day oil IP records in both the Middle Bakken and the Three Forks. The June and Chauncey wells in West Myrmidon established new records for the basin and oil production, with an average IP30 of almost 3,500 barrels of oil per day. The Arkin well in the Hector area, setting a new Williston Basin record for the Three Forks formation at an IP30 of just over 3,000 barrels of oil per day. And just to underscore the compelling economics of this well, the Arkin has already achieved payout.

Finally, a West Myrmidon well brought to sales in the quarter achieved a remarkable IP24 of over 10,000 oil equivalent barrels per day, but has not yet achieved 30 days of production. In part because we continue to bring on these basin-leading wells, we are proactively managing gas capture to remain in full compliance with all of North Dakota requirements and have the necessary flexibility to ensure no flow assurance issues as we continue to pursue this high-return program.

Eagle Ford held production flat sequentially and delivered results in Q1 that spanned the entirety of our acreage position. These included 11 outstanding wells in Atascosa County, with an average IP30 of over 1,600 oil equivalent barrels per day at an oil cut of 76%. The Eagle Ford continued its focus on enhanced completion designs and contributed significant free cash flow through the powerful combination of well performance and strong LLS-based oil realizations that were above WTI.

Oklahoma and Northern Delaware began their shift to primarily multi-well pad drilling that will dominate the remainder of their 2018 programs. In Oklahoma, oil production grew 25% sequentially, primarily from outstanding base performance that included the Tan infill that came online late in the fourth quarter. We largely completed our STACK leasehold program in the first quarter and expect to be greater than 90% HBP-ed in the STACK by year-end.

Looking ahead, 95% of our remaining 2018 wells to sales in Oklahoma will be in the overpressured STACK and SCOOP, the majority of which will come from 4 multi-well infills.

Northern Delaware, though still early in its development cycle, delivered wells across Malaga, Red Hills and Ranger areas at an average IP30 of 1,460 oil equivalent barrels per day at 69% oil cut. Late in the quarter, we brought the first 2 Cypress infill wells online ahead of schedule and we'll report results once we have 30 days of production from the entire pilot. Additionally, in the last 6 months, we've added 165 risked gross COOP locations, with an average working interest of 65% through trades and a small bolt-on and continue to pursue opportunities that increase our working interest, generate more operating sections and provide more extended lateral optionality.

It's difficult to speak about the Permian without addressing differentials and takeaway. We're currently benefiting from our Midland-Cushing basis swaps and open positions cover us for 10,000 barrels of oil per day at a discount of less than $1 to WTI for the second half of 2018 and all of 2019. Our swaps will help protect over half our forecasted oil production for the remainder of the year.

On takeaway, it is important to stress that today, Northern Delaware counts for only about 4% of our overall production mix. However, while we anticipate no flow assurance issues, we are planning for future growth and have expanded our oil gathering agreements and are assessing both gas gathering and FT commitments for the longer term. We are also transitioning our water-to-pipe throughout the year, which will reduce unit operating costs for the basin.

In addition to our 4 U.S. resource plays, we continue to generate value from our world-class integrated gas development in Equatorial Guinea, which contributed $124 million of EBITDAX for the quarter despite a turnaround at the LNG plant. This unique gas infrastructure, LNG plant, gas plant, methanol plant, is well positioned to not only deliver free cash flow today but also could capture additional equity and third-party gas as the natural point of aggregation in the region.

Our financial flexibility is at the top of our peer group and was further strengthened by receipt of proceeds from Libya and our final Canadian oil sands payment. This flexibility allows us to pursue multiple high-return uses of free cash, but we are taking a disciplined approach and we are not considering large-scale M&A.

Repurchasing shares is an option, and we have a $1.5 billion authorization already in place. And we can also look at our already competitive $170 million annual dividend. We have enjoyed higher pricing for just over a quarter. But as our confidence in sustainable free cash flow generation continues to grow, we will consider returning additional capital to shareholders, and it is a topic of ongoing discussion with our board.

Our objective is to strike the right balance between additional direct return of capital and accretive opportunistic low-entry cost resource capture. Specifically, we have successfully added quality operated locations in the Northern Delaware through trades and a small bolt-on and have captured over 250,000 acres across multiple onshore exploration plays, including a material position in the emerging Louisiana Chalk at less than $900 an acre. We recognize that these unique resource capture opportunities are episodic and challenging to forecast. We spent $94 million in Q1 and expect another $150 million in Q2, but they offer the potential to generate outsized full cycle returns.

We now expect to grow resource plays 25% to 30% year-over-year, up from 20% to 25% for both oil and BOE, with our development capital budget unchanged. And we expect our total company annual growth to be towards the upper end of our guidance, also for both oil and BOE.

But growth is simply an outcome of our returns-focused capital allocation. Thank you, and with that, I'll hand it back to the operator to begin the Q&A.

(Operator Instructions) We have a question from Guy Baber from Simmons and Company.

I wanted to start with the Bakken, but it looks like you continue to be successful in expanding the core of the footprint there. So really impressive well results from Hector, in particular. Can you talk about how that's influencing your view of the depth and the quality of your inventory there? I know you only recently highlighted over 12 years of inventory in the Bakken at this year's pace, but can you put some additional context around that? Just trying to better understand to what degree that inventory is economic, how it will compete, because the wells you're drilling right now were obviously very, very impressive.

Yes. Guy, maybe just for everyone on the call, we have talked about the Bakken having a forward inventory at kind of current activity levels of just over 12 years. And the way I think about our success in the Hector today is that we're continuing to delineate across that acreage position there. That's about 115,000 net acres. We have had very strong early success there, record-setting wells there. But we're still marching across that acreage position. And I view this as, thus far, really providing us an opportunity to uplift the intrinsic value and economics of that 12 years of inventory as we elevate the inventory that resides within the Hector area. Additionally, we are still looking to test other areas this year in the Bakken, including Elk Creek as well as the Ajax area, as we continue to apply the same workflows that started in West Myrmidon, transitioned then into Hector. We're looking to apply those as well in these other areas. So right now it's a great outcome. All credit to the team there for their innovation. They are competing strongly at the very top of the portfolio with these kinds of results.

And then for my follow-up, I wanted to talk a little bit about the resource play, leasing and exploration program. But you've obviously been successful in adding new acreage to the portfolio at low cost. I knew you characterize the spending there as episodic, and I'm sure you will be opportunistic. But how should we be thinking of the size or materiality of that program over time? Is there any framework that you could share? I'm really just curious as to how you instill a sense of discipline into the organization there to ensure that you're maximizing the full cycle return potential of the dollars that you're spending in that program as you highlighted.

Yes. Well, I think you said it well, Guy. It's very difficult for us to forecast in this area because typically, these unique opportunities are what we would classify as potential lost opportunities, meaning that if we don't act upon them, they're likely going to move away or at least the low-cost entry element of them will move away from us. So it is difficult for us to forecast. That's one of the reasons why we at least attempted to provide some visibility into the next quarter for you all. So that was an important element. I think as we consider the scope of it and ensuring that we do apply discipline to this element of our business, just like all other elements of our business, it starts with return and capital allocation. When the REx team brings in an opportunity, it has to compete on a similar basis as our other opportunities, meaning that there has to be a path there to achieve economics, full-cycle economics, that are competitive with our existing portfolio. These are still exploration plays with a finite chance of success. But we have to be able to see materiality, quality and value proposition, meaning that they can come in and compete for capital allocation. The other point that I would make just on the spend question is that as you think about the framework, although we're very excited about the greenfield leasing that we've accomplished, bear in mind that the real work comes after the leasing occurs. We have to get in there then and go through appraisal, delineation, and we hope it's ultimately predevelopment. And all of those activities will require capital allocation. So as we look forward in time, we have to also consider those future capital needs that are beyond just greenfield leasing.

The next question comes from Arun Jayaram from JPMorgan.

Lee, if the script is broadly correct, I just wanted to get your thoughts on potentially recommending to the board to return cash to shareholders. And just your views on, do you think the stock is undervalued and there's lots of good use of money, just given the strong balance sheet and the strong free cash flow generation of the company.

Yes. Thank you, Arun. Yes, first of all, I want to emphasize that return of capital to shareholders is and has been an ongoing dialogue with our board. We obviously discuss our dividend, which is very competitive in our space, with our board each and every quarter. So that concept of return of capital to shareholders and the constructive tension with other investment opportunities is front and center with the leadership and with our board each and every time we sit down to discuss it. What I would say is that, going back to my opening comments, that repurchasing shares is definitely an option. We have an authorization of $1.5 billion already in place. We can also consider the level of our dividend. Although at $170 million annually, it's very competitive, that also needs to go into the calculus. And you're right, I mean, we -- certainly, as we look ahead, we absolutely see the opportunity to get into a mode of sustainable cash -- free cash flow generation. And I think as we move through that, returning additional capital to shareholders will feature in that forward dialogue. I would maybe mention though just a few things there is that, first of all, we feel that we need kind of a minimum cash balance to run our business given the scale and scope of it of around $750 million of cash on hand, and that's plus or minus. I would also point out that all companies are at different stages in their respective business models. We have addressed our balance sheet very clearly last year. We've also largely completed our major portfolio dispositions, meaning that we don't expect additional near-term material proceeds. As I was just chatting about with Guy, we also recognize that leasing cost is just the first step in capturing some of the low-entry cost opportunities, so we must consider those future capital needs as well. All that to say is that the bottom line is that all of these factors go into our considerations for pursuing what is the best -- what are the best options for long-term value creation through the use of free cash. And I view it as it's not an either/or proposition. We see multiple uses for that, including enhancing our direct return of capital. All of that can be accommodated.

And just a follow-up. I just want to talk a little bit about the Louisiana Austin Chalk opportunity. Obviously, in the late 1990s, the industry tried to move into Louisiana with no success there. But I was just wondering if you could talk about this opportunity? And obviously, EOG has an interesting discovery well, the Eagle Ranch #1. And if you could talk about maybe the proximity to some of the EOG acreage?

Yes. Well, we plan to provide many more details as we move through the year. But obviously, the Louisiana Austin Chalk, as you mentioned, did go through a bit of a development phase. It was with very early technology designs on the completion size -- side and relatively short lateral lengths as well. We see this as a natural extension of kind of this Austin Chalk megatrend that goes from Mexico across South Texas, all the way over to East Louisiana. And having been one of the leaders in the development of the Austin Chalk in South Texas, we think we're well equipped to get in here and appraise and understand the potential of this. But I want to stress again that this is exploration, and until we are able to get out in the field, do the necessary technical work and get some wells down, we don't really what we have here in terms of forward inventory or resource. But it's exciting. And I won't get into where we are on the map, Arun, because we're still obviously active in the play today, and so I don't think it's prudent for us to talk those specifics at this present time.

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

Lee, I wonder if I could kick off with the relative capital allocation across the plays. The Bakken obviously continues to impress in terms of incremental well results. So I'm just curious as to, within your stable capital spend for the year, how are you seeing incremental spending in the event the oil prices did stay at these elevated levels?

Yes. Doug, we are -- as we said before, we have calibrated our development capital program at a level that we're comfortable with. We believe it strikes the balance between generating those very strong material improvements and corporate-level returns that we talked about early on a strip deck. We can -- we see cash return on invested capital improving year-over-year by about 65%. We will always be looking to, I would say, adjust our capital allocation based on new information throughout the year. But our $2.3 billion development capital spend, that is our spend for the year regardless of where commodity prices tend to track for the rest of the year.

I guess, to be clear, what I was really -- it probably wasn't obvious in my question, what I was really getting at was the relative oil cuts in the Bakken relative to the rest of the portfolio. Would the high oil price impact your decision as to where your relative investment shifts within that stable budget? Obviously, you step-up in the Bakken, I guess, is what I'm asking.

Yes. I've got it, Doug. The beauty, I think, in our portfolio today, in our multi-basin model is, Doug, is that we are already biased very heavily toward oil opportunities. And you're right, the Bakken offers very high crude cut. But I would also point out that even in Atascosa County, we're riding upwards above 75% C&C crude oil cuts there as well. So that does go, and we look at obviously the product mix, but we're more driven by making sure that we're deploying to the correct overall economic value proposition. And today, when you look at our relative capital allocation that we described earlier in the year, it's not surprising that a big component of our capital allocation is flowing to both the Bakken and the Eagle Ford while we progress the early development phases from a strategic standpoint certainly in both Northern Delaware and Oklahoma. So we feel that we have already accommodated that -- not only the oil cut but the overall economics that we see in the Bakken in our capital deployment. But again, as we get new data, we can always look at adjusting and redeploying within our multi-basin model. But I want to stress that the $2.3 billion is the development capital that we'll be working within.

Appreciate the full answer. My follow-up, hopefully, a quick one. Last quarter, Lee, you talked about reevaluating the black oil in Meramec. I'm just curious if you've got any update sort of this quarter, could share, and I'll leave it there.

Hey Doug, this is Mitch. I'll see if I can address that for you and I'll carry on and probably I'll hit what you're looking for. But maybe I'll start with breaking down our position a little bit just for context and in the slides. But 70% of our operated DSUs in the STACK are in the overpressured window, and about 30% in the normally pressured. And you'll note that for the remainder of 2018, our focus is really in the overpressured areas. How I would describe it is we completed our first phase of infills in the normally pressured window, the last one of course was the Cerny. The most recent one, which we did a multi-horizon test there, including in Meramec, Osage and Woodford. We've made a massive data set of production, subsurface and intentional data acquisition. We're now integrating that into the same kind of internally developed workflow, multidiscipline integration work flow that we've applied in places like the Eagle Ford and Bakken to drive the results that you're seeing from us there. I would note and just kind of keep in mind, in those 2 basins we've got about on the order of 1,500 infills, whereas in the normally pressured window, we've got 19 infill locations so far. At a different phase, we have taken a few very significant learnings thus far and continue to optimize while we focus in the overpressured area and come back. But the Cerny Meramec wells were delivered, about $700,000 completed well cost lower than the Eves, and through the first 60 days, we're seeing oil cums that are comparable. So no degradation in performance there. And we believe we can take costs down even further. We're currently evaluating the design that's more in the $3.5 million completed well cost range. So continuing to advance our learnings, more optimization to do. And while we're in that integration and compilation phase, we're going to shift our focus more into the overpressured area.

Mitch, I appreciate the full answer, maybe I'll just go on a quick follow-on to that. Just the prior operator had obviously put up some pretty aggressive wells or some pretty aggressive fracs. Is there any consequences of that in terms of your ability to optimally develop it? Or do you feel that's not going to be an issue over stimulated, the prior one if you like?

Sure, Doug. I wouldn't characterize it the way -- in the way you last stated it. But what I would say is, as we look at the ultimate development plan here, as with all other operators, you have to consider the history of that DSU, and, frankly, the surrounding DSUs. And so the majority of our DSUs do have a parent well or direct offset. That would be true for our industry as well. The best we can tell, our position there is not too dissimilar from the rest of industry if you consider parent Meramec, Osage or Woodford wells across the STACK normally pressured area in particular.

The next question comes from Ryan Todd from Deutsche Bank.

In the Eagle Ford you mentioned that your results are expanding the core. Can you give a little more color on what you're seeing? How you see the core evolving, whether this is kind of improving the economics and the quality of your existing inventory or whether it's actually expanding the inventories you see going forward?

Sure, Ryan. This is Mitch again. I think if you look back over the past 3 or 4 quarters, we've been highlighting, in addition to the core Karnes area, our activities down at Atascosa, which don't have -- don't benefit from the same quality of rock and necessarily same fluid mix. But we, in taking that multidisciplined approach that I described earlier, have gotten onto a pretty refined state where we're actually designing the combination of wells basin and completion style sub-regionally and in some cases, down to the DSU. What that's translated to as we modified our designs is a significant operating or uplifting of the inventory outside of core Karnes County. And that's why we keep sort of highlighting the results from Atascosa. So in general, I would say the pressure is on upgrading the returns. The focus is on value optimization. Not a significant change to overall inventory.

That's helpful. And then maybe in the Permian, the -- I mean, during the quarter, you added 165 risked gross locations, which is a pretty significant number there via small bolt-ons and an acquisition. I mean, how do you -- how would you characterize the ability to continue to high-grade the portfolio in this way, either through swaps or small bolt-ons? Is there a decent amount of running room?

Yes. I think -- this is Lee. I believe that there remains an incentive for all operators to continue to drive toward more contiguous positions, particularly in Eddy and Lea County in Northern Delaware. I think the progress that the team made over the last 6 months since we really closed those deals is very solid. But this is going to take time, particularly when you start discussing trades. You have to get to the point where you get to an equivalent value proposition with another party. So the incentive may be there, but as I like to tell people, no one likes to say they have the ugly baby in the trade. And so it just takes time. And a lot of times, those trades are going to come in smaller bits as well. But we have a dedicated team that is focused on this. We believe that is important for that asset going forward in time to continue to block up what we believe is a great acreage position in Northern Delaware. And we'll keep you all posted, But again, it is going to be -- it's going to come in probably fits and starts and probably in small parcels, particularly on the trade side. But it's something that our asset team and our land team are squarely focused on today.

Outside the swaps, are you seeing -- in terms of ability for bolt-ons, is there much depth there? or are there pretty limited opportunities?

Yes. I think for us, the key thing that made that small bolt-on in fourth quarter very attractive was it was essentially a laydown in our Malaga area. So there was great synergy. It ticked all the boxes for us. It converted non-op locations to COOP locations. It raised our working interest. It gave us more optionality for extended laterals. So it was really almost the poster child for what we're trying to do. And those -- that's going to be a small group of opportunities that can tick all those boxes and really be a synergistic and accretive add to our position. So we're going to be very selective. These are going to be smaller in scale. We obviously are not looking at any large transactions here. But to the extent that we find other transactions and that transaction in 4Q was kind of a $60 million deal, we're going to evaluate those and if it fits, we're going to move on them. And that's one of the advantages of having the financial flexibility that we do today.

The next question comes from Bob Morris from Citi.

Looking at the 2 very big West Myrmidon wells that had 24 IP rates of almost 11,800 barrels per day, can you give us a little bit of color around how much of that strong performance was being better able to identify sweet spots, more landing zones? And how much of it is just a continued evolution of your completion designs here. And probably what I'm trying to determine is how repeatable is that in that performance curve on Slide 8 continuing to move up and looking at how that is going forward?

Sure. Thanks, Bob. Let me come back to a couple of points I made earlier, and then I'll expand on that little bit. But I hope you will understand, we're not going to reveal sort of the full detailed recipe of how we're doing what we're doing. But I'll say it starts with the tremendous technical database that we've developed. The team that we have there really refining the multidiscipline integration of that and the reservoir characterization that allows us to then design a completion that takes advantage of the local characteristics. Supplement that with the culture that we've been building over the last few years, which is never to be satisfied with yesterday's results. And what it's taken us to is an approach that allows us to customize to a very subregional level. And if you'll look at our completion details across the basin, you'll very clearly see that we don't have a one-size-fits-all approach. We custom design to take advantage of what we understand about local characteristics. The Hector record -- record Three Forks well from Hector, the 2 West Myrmidon wells you mentioned, those records weren't delivered by accident. It's true that there was good rock to start with. But our completion designs were tailored to take advantage of the characteristics there. And so it's a value optimization focus that drives it and a really refined multidiscipline integration of those large database that we have.

Okay, great. Obviously, that's working extremely well. A follow-up, just quickly on the Cerny pilot. From the 3 Meramec wells there, was there already an unbounded parent well on that section? And then also did you see vertical communication between the Osage and the Woodford formation in that pilot?

Sure. The Cerny did have a parent well. And so just as a reminder, we drilled 3 additional Meramec wells across 2 landing zones in a half section there. And then we drilled 1 Osage well and 1 Woodford well. The solution out there, as we've talked about several times, is going to be fairly regional and very specific down to the DSU level in some cases. In this particular case, we did see some communication between Osage and Woodford, but not between Meramec and those intervals. I wouldn't say that, that result is necessarily translatable across long distances. We're going to need to do more multi-horizon tests to fully understand that and to optimize the solution.

The next question comes from Brian Singer from Goldman Sachs.

You're pretty clear that the $2.3 billion budget looks like it's going to hold here almost regardless of the commodity environment. But kind of back to the question on activity levels in the Eagle Ford and Bakken, whether now or even in 2019. Are there constraints that you see to increasing activity relative to where -- what your existing plans are from either ability to get things done, perspective inflation or just erosion of efficiency or productivity gains? Or do you view the decision to be fixed in the $2.3 billion in the areas you're at as purely a capital discipline choice?

Yes. Well, I certainly I believe that the $2.3 billion is a capital discipline and returns-driven choices that we are making. There's nothing intrinsic in either basin that is limiting us today from an activity standpoint. Obviously, we look to drive maximum efficiency, i.e. running our frac crews 24/7, et cetera. All those things come into play. But when I -- I think the way, again, to think about 2018 for both of those basins is Bakken is absolutely on a growth trajectory, but it's also going to generate free cash flow this year. Eagle Ford, we are managing to a more or less flat production profile in order to take advantage of its capital efficiency and ability to generate free cash flow to drive other elements of our portfolio. I think on your question around, you mentioned, inflation. Thus far, we feel that the inflation assumptions that were implicit in our original $2.3 billion plan are still holding true. And so we -- although it's something that our teams not only look to manage but actually look to offset each and every day, we feel very comfortable at this stage that we have that accounted for fully in our $2.3 billion development capital budget. 2019 is something that we're really not talking about quite yet. But obviously, the Bakken and the Eagle Ford as well as our other basins will all be part of a multi-basin optimization as we go into 2019. And we'll allocate capital based on the best available data when we go through our planning cycle. So nothing is locked in and there are no constraints around the Bakken and the Eagle Ford of today that would not allow us to flex those assets up or down.

My follow-up is with regards to Oklahoma, and we talked -- some talk here about the STACK area. Any update of note or learnings or key milestones ahead on the SCOOP side of the equation?

Yes. Brian, this is Mitch, again. I guess, we've got the remainder of 2018 focused on overpressured infills across STACK, and then some infills down in the SCOOP area as well. And we've highlighted those, I think on Slide 11, if I recall. And so we will have some inflow of information with a couple infills down there. But nothing to report today.

And I think, just as a reminder, Brian, because the SCOOP is clearly HBP-ed, we have had the optionality to not necessarily drive activity there until we are ready to do so. And -- but we will have some multi-well infill drilling there this year, 2018, and it will continue on that path.

The next question comes from David Heikkinen from Heikkinen Energy Advisors.

Just one quick question. You had talked about progressing in Kurdistan. Can you provide an update there?

Absolutely. This is Lee, David. We are -- as a reminder, David, for everyone online, we have 2 nonoperated blocks in Kurdistan: Sarsang and Atrush. We have a small working interest in both of those. Sarsang, there is already an executed sales agreement in place and we are looking to, again, moving that toward close. I would say that we continue to progress agreements around the Atrush block as well. So it is certainly reasonable to expect, ultimately, a full and complete exit from Kurdistan.

That's helpful. And I thought your comments on the needed cash balance were pretty interesting and talked to the scale needed to really prosecute a development program in the multi-well development mode. Have you talked -- thought about or talked about in the past, the amount of capital needed from initial wells spud to last well put on production. Just thinking about the amount of working capital that's getting put in the ground and that need as you think about the next couple of years by the STACK or the Delaware or the Bakken really?

David, this is Dane Whitehead. We spend a lot of time thinking about working capital. The way you frame that question is a little bit different to me. But let's take it back to the $750 million. I think within a given month, and we kind of saw some of that this month. You're going to see interim month working capital swing of north of $400 million, maybe at the $500 million, especially when commodity prices go up like they have. It really influences things. And so that's really kind of an important -- it's a very important data point now would calibrate that $750 million. Plus it's nice to have a little extra flexibility in there in the event if something comes along or something like that.

I would also maybe add, David, this is Lee, that the point you raised around as you get more toward multiwell pad drilling and as the number of wells on pad increases, these traditional kind of short-cycle investments do start looking more like medium to long-cycle investments, and you need to plan that within your budget cycle and how you approach capital allocation, and it also presents, I believe, even some forecasting challenges, particularly when you look at quarterly results because clearly, if you have a large pad that moves out with the quarter, it could have dramatic results within the quarter, but not necessarily within the calendar year.

That's definitely the challenge of near-term versus an intermediate and longer-term perspective. And great results in the first quarter.

(Operator Instructions) We have no further questions at this time. I would like to turn the call over to CEO, Lee Tillman, for final remarks.

Thank you, Hilda. I'd like to end by just thanking all of our dedicated employees and contractors for their efforts in the quarter and, certainly, their efforts going forward. At the end of the day, they are sustainable competitive advantage. I want to say thank you for your interest in Marathon Oil. And that concludes our call.

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