Zach Dailey - Director of Investor Relations Lee Tillman - President and Chief Executive Officer Mitchell Little - Vice President of Operations Dane Whitehead - Executive Vice President and Chief Financial Officer.

Guy Baber - Simmons & Co. Ryan Todd - Deutsche Bank Securities, Inc. Edward Westlake - Credit Suisse Evan Calio - Morgan Stanley Doug Leggate - Bank of America Merrill Lynch Paul Sankey - Wolfe Research, LLC Brian Singer - Goldman Sachs Pavel Molchanov - Raymond James & Associates, Inc.

Scott Hanold - RBC Capital Markets Robert Morris - Citigroup Roger Read - Wells Fargo Securities Jeffrey Campbell - Tuohy Brothers Investment Research, Inc. Arun Jayaram - JPMorgan Securities LLC.

Welcome to the Marathon Oil Corporation 2017 First Quarter Earnings Conference Call. My name is Paulette, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session. 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 first 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; and Dane Whitehead, Executive Vice President and CFO. 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'd request 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 discuss 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 to all and thank you for joining us today. I'll have a few opening comments, then we'll get straight to your questions. We have been resolute in our transformation of Marathon Oil from an integrated company to a globally diversified independent to the U.S. resource play focused independent E&P we are today.

We're now the only independent E&P with material positions and therefore highest return lowest-cost oil-rich basins in the U.S.

We continue to execute against our playbook by strengthening our balance sheet, resetting our cost structure, simplifying concentrating our portfolio, and positioning our business to grow profitably within cash flows at [moderate] oil pricing.

With our transformative transactions in the first quarter, exiting the Canadian oil sands and entering the Northern Delaware, we have further accelerated toward our strategic intent.

We believe our differentiated portfolio, visibility on long-term growth within cash flows and execution strength, our foundational characteristics of a business model that offers a very compelling investment case for our shareholders.

We have the balance sheet, cost structure and leadership to accelerate value from our portfolio beginning with the resumption of sequential growth in the resource plays in the second quarter. We're still on plan to see this growth increase in the back half of the year, with anticipated exit production rates 20% to 25% higher than 2015.

We've also raised our full-year E&P production guidance by 5,000 boe per day and successfully ramped activity to 20 drilling rigs during first quarter from 12 rigs at year-end and we currently standard at 22 active rigs inclusive of our rig in Northern Delaware.

We're on track to prepare the STACK for full-field development to maintain Eagle Ford production flat for free cash flow generation, to develop the high-value high-oil cut Myrmidon area in the Bakken, and to be running at three rigs in the Northern Delaware at mid-year.

This quarter, North American production exceeded the high end of guidance, and the resource plays were flat sequentially as we prepare for growth in 2Q. In Oklahoma, we brought to sales only the second industry black oil infill test in the normally pressured window, and it is performing in line with expectations.

In Eagle Ford, our deliberate focus on the oil window increased oil production 7% sequentially, and we continue to take advantage of our scale and efficiency. In the Bakken, we continue to prove up the competitiveness of East Myrmidon via a high-intensity stimulation designs, which we're expanding to the hectare area this year.

And finally, in the Northern Delaware, we closed on the BC deal just this week, are well along in building a high-performing asset team, and look forward to our first Marathon design completion in 2Q.

Our portfolio on business model have never been stronger or better positioned to adapt to a volatile commodity market, with over 95% of our capital program dedicated to the U.S. short-cycle investments.

About 60% of our total production this year will come from the resource plays, and that mix will only continue to improve as we grow the U.S business over the next five years while enhancing our returns and our margins.

2017 is poised to be an exciting year for us, and our longer-term growth plans will now benefit from optimization across four basins.

The integration of the Northern Delaware into our long-term capital allocation plan will only strengthen our confidence in delivering against our benchmark CAGRs of 10% to 12% total company, and 18% to 22% for the resource plays from 2017 to 2021 within cash flows, and at a flat $55 WTI.

Our near-term and longer-term plans are further supported by a strong balance sheet with $2.5 billion of cash and a consistent cash flow generating E.G. business that provided $160 million of EBITDAX this quarter to reinvest back into the resource plays.

While we can't predict future commodity prices, we have purposefully designed our 2017 business plan to be flexible and retain the ability to respond to the macro environment with many levers at our disposal should we feel the need to adjust. With that, I'll hand it back to the operator to begin the Q&A. .

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Guy Baber from Simmons and Company. Please go ahead..

Thanks very much. Good morning, everybody..

Good morning, Guy..

Lee, my first question was. I wanted to follow-up on the last comment that you made there. So just maybe get a sense of the flexibility embedded in your current plan given some of the volatility in the market.

Are they trigger points with respect to commodity prices, where you begin to pull back on the rig count at some point? I mean just given the volatility, I want to better understand how you plan to manage the business through the cycle here, and you mentioned many levers at your disposal, do you care to discuss that a bit at all?.

Yes, absolutely. Maybe, Guy, just a few comments on the macro in general first, and then I'll talk a little bit about how we might respond. I still think our belief is 2017 is going to be very volatile, probably in a bit tighter band if we continue to see OPEC discipline.

We do feel that supply and demand have come back largely into balance, but as we all know, storage has continued to be a bit stubborn.

We're not going to even attempt to predict pricing, but as I said in my opening comments, we've really focused on making sure our business plan has the flexibility and optionality that if the fundamentals do support adjustment, not technical changes, but the fundamental support adjustment then we are ready to do so.

The levers that we have available, I think it starts with the fact that now a 95% of our capital program is in the short-cycle investments, we have minimal long-term contracts associated with our U.S. business, and we've got a balance sheet today that sits with $2.5 billion of cash and an untapped revolver.

So in the event that we see the fundamentals supporting a price that is in the 40s, we've got a lot of tools available to modulate or spend and mitigate our exposure. And obviously, we'd expect service cost to start following that price down as well. We can't have low prices and high service cost, that just can't be sustainable.

So in that scenario, we're going to revert back to our capital allocation priorities. We're going to ensure that our strategic priorities in Oklahoma and the Permian, Northern Delaware are met, and then we're going to take a hard look at our discretionary investments based on the available cash flows..

That's very helpful. And then I wanted to ask an operational follow-up, but the Eagle Ford results this quarter looked especially strong.

Can you maybe talk a little more about those enhanced completions there, the intensity of those completions, lateral links, what you're seeing with inflation as well? The $4 million well costs would seem to indicate you aren't seeing much of there.

And then you look like you had some really good results in Southeast Atascosa County as well outside of your typical Karnes focus area.

Can you talk a little bit about that, and how that might influence your go-forward plans in the Eagle Ford?.

Yes, absolutely. Guy, this is Mitch. A number of questions in there, I'll try to hit them all, but check me if I miss one along the way. But you've seen us move up our completion intensity over the back half of 2016 and into 2017.

The majority of our wells were pumping at 2,000 pounds per foot, 200 foot stage spacing in the oil window, which is where the majority of our program is concentrated.

We've been in the process extending those enhanced completions down to the Southwest as you referenced in Southeast Atascosa, and really pleased what we're seeing there on those Guajillo pads that we released.

And even as you extend that up on trend to the Franke May A pad where we pumped a little bit higher intensity, early results are certainly encouraging.

We've got a number of additional tests that we'll be bringing online through the year, and with a little bit more production history and confirmation from those tests, we're encouraged by kind of upgrading that inventory and making it competing quite favorably with the rest of our Eagle Ford portfolio there, so certainly very encouraged by that.

On the inflation side, like many are seeing, they're variable by service line, but seeing some pressure on the completion services side. But thus far, the teams are working really hard and focused on offsetting the majority of that.

We noted a new record well performance at over 4,000 feet a day, about a 1/4 of the wells were delivered at 3,000 feet a day. And that’s why we were standing up a couple of cold-stacked rigs which we added late last year, so pleased with that.

We're also tweaking designs, the completion recipe, reducing some of the higher cost elements to offset some of that. So certainly a bit of pressure there, but we've been successful in mitigating the majority of it. And the teams are focused on continuing to innovate and find operational efficiencies to keep that under control..

Great, thanks for the comment..

Our next comes from Ryan Todd from Deutsche Bank. Please go ahead..

Maybe let's start out in the Yost infill pilot. You had some solid results there in the pilot.

Can you give a little more color on takeaways from the six wells, including any change to your thoughts on, if there's been any change in your thought on proper spacing within a unit? And should we expect to see these shifts to longer laterals going forward?.

Absolutely, Ryan, as you said and as we noted, the Yost is the second full section infill in the black oil window. We're pretty satisfied with the early results there, matching our expectations.

We've got taken away a number of learnings there, probably the main take away is that six well per section density confirms our base case when we made the PayRock acquisition. As we go throughout the year, including the Hansens infill, that's next up.

We're going to test a little bit tighter density and add another well in the Meramec per drilling unit, also taking a look at the learnings from the Yost's pilot, tweaking the completion design a little bit and testing a bit of a gap out from the parent well.

In that particular case, we see a little bit higher fracture, natural fracture intensity around the parent well. And so it's appropriate to modify the design for that particular spacing unit.

And keep in mind, we design spacing at the individual spacing unit, integrating the subsurface data, micro seismic and other fracture characterization techniques that take into account the local rock mechanics and fracture characteristics that we can model. But early in the program, we're pleased with the results, the productivity.

The Yost's pilot was also a little bit shorter than full section, about 4,600 foot lateral length, so thus far so good, I'd say we're encouraged and have kind of confirmed the base case assumption in that acquisition, and we'll continue to take our learnings and apply additional optimization to the next few as we optimize ultimate spacing for that area..

Okay.

And should we expect to see a lateral length increase as you move forward in the area?.

We've got a portion of our acreage that's amenable to XLs. What we have seen thus far is that the SLs on a per lateral foot or capital efficiency basis are competing and in some cases, exceeding the performance of the XLs. So we don't see necessarily that XL is the right approach in the black oil normally pressured window..

Okay. Thanks that's helpful and then maybe just some thoughts around your full-year guidance. I mean, the volume looks great in 1Q, 2Q guidance was a little bit better than we were expecting in your completion schedule is certainly back-half weighted towards – as we move through the year.

I mean, how do you see about the potential? Is the full-year guidance at this point, does it feel conservative given what you're seeing? Is there – how do you think about the potential for that to move higher over the course of the year?.

Well, we feel confident in our ability to deliver against the revised guidance, Ryan and I think we've done a lot of good work.

You've seen in the first quarter, essentially a flattening of the resource plays, we're essentially flat sequentially there, which sets us up very favorably now with the uplift in activity to get back on that sequential growth track. But your observation, of course, of that gaining momentum in the second half of the year is an accurate one.

As we continue to learn more and as we feel more confident, we'll continue to re-examine that guidance each and every quarter based on actual field data. But it's still pretty early in the year for us, we're still early in the – even though we've ramped rigs, bear in mind that, that kind of the leading indicator, the completion still has to follow.

And so we still have a lot of work in front of us, and we're going to watch it carefully, and update as we see appropriate..

Okay. Thanks Lee..

You bet..

And our next question comes from Ed Westlake from Credit Suisse. Please go ahead..

Yes, good morning and congrats on the strong cash flow and the progress. I mean maybe if I could start on the Delaware, just maybe some sort of high-level comments about the time it's going to take you to delineate the acreage. Obviously, there's some very strong industry-wide results around that.

And then how the response has been post-closure from the service providers in the area and the infrastructure providers, which obviously, you need to step this asset up into development mode..

Yes. Sure, Ed, this is Mitch again. Clearly, we just closed on the BC part of the deal earlier this week, but we're quickly advancing our near-term activity and appraisal plans. Through the rest of the year, the majority of the activity will be targeting Bone Spring and Wolfcamp intervals, and of course, lease protection.

Nominally, we need just under two rigs dedicated to protect the leasehold. We'll certainly be doing that. And as we get later in the year, we'd expect to begin drilling a few pads. Certainly, we see areas where sufficient delineation has already occurred and can move to optimizing well spacing in those areas.

And we'll also be looking to drill a multi-bench pad, still finalizing the design on there as you might expect.

But current thinking we'd be looking to test three to four benches, probably six landing zones, all in combination, gathering technology, micro seismic and other technologies that help us characterize fracture behavior and rock mechanics in the areas that are a little less delineated, and we'll be testing various well spacing there as well, likely four to six well per bench type spacing.

Building out marketing plans and infrastructure development plans in coordination with building out that detailed plan of development. So well on our way to three rigs by midyear, look forward to a busy second half of the year where we'll bring 15 to 20 wells to sales and as you mentioned, encouraged by the continued extension of the play.

The BC Red light well, which was western and step-out in Eddy certainly looks good and some of the other wells that are pushing the play and also proven up some of those zones that we consider as upside targets in the acquisition. We released, or others have released a couple of nice Avalon wells over in Lee County..

Okay, great. And then switching basin, I guess, further south in the SCOOP. I mean, you've got the Springer four-well pilot coming on in the middle of the year. Obviously, your peer, Continental's talked about the Sycamore, which is above the Woodford.

Maybe some general thoughts as to how the sort of SCOOP has economics or potential has changed, obviously there's been a lot of focus on some of the other areas, so within the Marathon portfolio..

Yes, sure. As you know, we will be drilling our first company-operated Springer infill down in the SCOOP. Those infill programs in the Springer oil window have really strong economics, and we're pleased to be seeing how that's developed, and we've got some running room there.

Obviously, we're taking note of and paying attention to some of the Sycamore tests that are being released in that area. Our priorities, as we've talked about previously, are moving towards full-field development in 2018, where the majority of our activities will be pad-based drilling, both in the STACK and the SCOOP.

And so we're happy to learn from, we're paying close attention and watching others derisk some of these plays but we certainly have exposure to the Sycamore and the SCOOP areas as well..

But, Ed, I would just maybe add, there's no doubt that the Springer oil competes very favorably at the top of our portfolio. It's a matter of priority, that acreage is largely HBP, it held by production, so we've got the optionality to feather that into the portfolio at the appropriate time.

But we're looking very much forward to the downspacing test there, and we believe it's going to compete very favorably for capital going forward..

I think that’s what I was trying to get. Thank you very much Lee..

Thank you. And our next question comes from of Evan Calio for Morgan Stanley. Please go ahead..

Hi. Good morning, guys..

Good morning, Evan..

Lee, you've restructured the portfolio for conventional basin positions and one of the most active programs in 2017, amongst all peers 20 rigs today.

I mean can you discuss how you changed your organization and integrated the two new assets, or built your Permian team? And how do you think about operational capacity to execute on this big resource?.

Right. Well, certainly when we did some of the restructuring in the operations side of the house last year, bringing all the operations under a single leadership, it was envisioned that we would have the optionality to transition a fourth basin into that structure.

So we've built that structure with a mindset of bringing in a fourth basin into play, and making sure that we had both the technical and execution capacity available to drive that. Clearly though, in this case where we're standing up, a full asset team, one of Tom Hellman's first priority is building out that team.

And we're building that from both internal resources as well as some select external hiring. When both of those groups having a very deep knowledge in the Northern Delaware. But our operational structure as a whole was really designed to plug in a fourth basin that was part of the design from last year. So I feel very good about that.

From a capacity standpoint, Tom's well on his way of filling out the key leadership roles on the asset team. Of course, we have the transitional services agreement with BC operating as well, which provides us some incremental support.

And, so we think we're off to a really strong start there, and we're absolutely looking forward to getting the first Marathon designed well down in the second quarter. But I expect very little loss of momentum there as we kind of pick up the bit there in Northern Delaware..

Great. And if I could follow-up on the Yost, specifically.

I mean how much, with any frac interference did you see that gives you confidence in the upcoming seven- and nine-well per section test? I mean it sounds the parent-child wells could be optimized further from your results to support an even better results than some of the offsets there have been by their operators have been strong? Just kind of any color there to follow-up on Ryan's question..

Sure, Evan. Yes, we had a really strong parent well at the Yost and also, from our subsurface integrated workflow noted some higher natural fracture intensity around that parent well. And so it's fair to say that we did see some communication impacts as we came back in and infill that.

We'll take those learnings, and have taken those learnings into the Hansens. And we do think there's optimization that can be done, and we'll be changing the completion recipe a little bit as well as the gap-out test that we're doing on that location.

So very early days, we're certainly encouraged by the early results, kind of confirming the base case, but like any of these programs that you're in early days, there will be some optimization to come..

Got it, I mean I'll just slip a small one in if I could, will you under lifted in 1Q? Was there an under lift in 1Q?.

In the UK, yes..

UK yes..

For about 6,000 barrels a day?.

We have to get back to you, Evan. I think we can get back with you on that one. I’ll tell you the exact number, Evan. We had essentially, yes..

We didn't have a crude lifting in Brae..

Yes. We had no crude liftings. And obviously, it got concurrent on liftings in Libya, and so it's caught up there..

Okay, that was equal to sales and production. That is helpful. Thank you..

Yes, you bet. Thank you. Thanks for the questions..

Our next question comes from Doug Leggate from Bank of America Merrill Lynch. Please go ahead..

Good morning everyone. Good morning Lee..

Good morning, Doug..

Lee, on a Hector, you're adding a couple of rigs back in an area that I think you had previously characterized as obviously not as good as the Myrmidon, but I don't want to call it non-core, but certainly it's sort of well over 100,000 acres, if I recollect..

Correct..

Bigger completions seem to be having a fairly sizable impact on some of your peers.

Can you just walk us through how Hector is emerging to compete in the portfolio because I'm guessing that's a fairly large oil inventory or oil levered inventory that could be significant in your outlook?.

Yes. Your observations are spot on. The Myrmidon area, we typically characterized as being around 60,000 net acres. The Hector area, as you correctly stated, is around 115,000 net acres.

I think we would absolutely have characterized Hector as being a lower tier from a quality standpoint to Myrmidon, but the same modeling that we employ to give us confidence and the response we would see in the Myrmidon area from the higher intensity completions.

We've applied that of course, in the Hector area using the production data that we also have available there and feel confident that we're going to see uplift there and the potential of course to drive those to compete. They compete today, but certainly, we're looking to take them really to the next level.

We've seen great response West and East Myrmidon, and now it's really the extension of that into the Hector area, and we'll see kind of the first wells to sales really in the Hector area in the second quarter of this year. I don't know, Mitch, if you want to add anything else..

I think you covered it well.

We have done the same technical workflow, seen very material improvements in the Myrmidon area, and we're certainly hopeful that we'll see that same type of uplift or a significant uplift on the Hector program and with the twice the acreage position down there, certainly encouraging results would lead to a nice enhancement to a big part of our portfolio up in the Bakken..

I would also, maybe just add that a lot of our recomplete opportunities also sit in the Hector area, and we expect to have good response and good success from that as well..

My follow-up if I may, Lee is a couple I guess over a year-ago, now you were one of the first to put out a chart that kind of characterized your economic inventory by area and by oil price.

I'm just wondering obviously the portfolio has changed an awful lot in that time, could you characterize how you would see the incremental dollar? I realize a rising oil price is not a scenario anyone's catching right now, but how does the – what's the relative economics today in terms of what's the best part of your portfolio today if oil prices continue to fall?.

Yes. Setting the absolute price aside for a minute, and talking about relative economics in the portfolio, we would still see kind of occupying that top spot in the portfolio today. The Meramec black oil window, the [indiscernible] oil window in the Eagle Ford, West Myrmidon and now, of course, Northern Delaware, Wolfcamp and Bone Spring.

I would also argue, even, though we didn't necessarily feature it on the chart, some of the earlier dialogue around the Springer formation, some of those wells would be quite competitive. And as we're successful in uplifting things like East Myrmidon and Hector, we want to drive those toward that absolute top tier as well..

Okay. I appreciate the answer. Lee, thank you..

Thank you..

Our next question comes from Paul Sankey from Wolfe Research. Please go ahead..

Good morning, Lee..

Good morning, Paul..

When you started out – during your commentary, you said that Marathon is unique as far as you're majorly positioned in all four plays in U.S. unconventional, that's not something the market really likes, in so far as it would prefer focus. Can you talk – but it's also very interesting position, obviously, because you have the view of all four.

Could you sort of justify why you would want to be in all four simultaneously, and why given the information you presumably have, you wouldn't just focus on one aggressively? Thanks..

Yes, I think multi-basin approach does provide some inherent advantages. And I think, first of all, it's a multi-basin approach in four basins that are resource plays and oil-rich resource plays, so it's very consistent with our strategic intent.

But we see a great deal of value in having resource plays that are at various points in their developmental cycle.

Being able to transfer learnings from the scale and efficiency that we've delivered in places like the Eagle Ford, and drive that into day one, into places like now Oklahoma and Northern Delaware, we see as an inherent advantage in the multi-basin model.

Additionally, if you're looking to ensure that you can drive competitive growth and do that within cash flows, having mature assets, more mature assets that can be modulated between growth and free cash flow generation, we also see as a significant advantage.

So the sharing, the learnings, the best practices that you can drive from our experiences in places like the Eagle Ford and the Bakken.

And now we'll also start seeing reverse integration from the newer plays where the Oklahoma teams or the Northern Delaware teams provide us insight that can be plowed back into our basins like the Eagle Ford and the Bakken. All of that, to us provides some implicit advantages.

And all four basins also have very unique product mixes as well, that again, allow us a little bit different exposure and a little different optimization, depending upon what we see in the market. So we do see some advantages in the multi-basin model.

We like the fact, of course, that, that model is first and foremost focused though in those four resource plays that are of very high quality and very oil-rich..

Yes. I think the perspective of different phases of development is interesting. It feels as if there was one that would be the Bakken that needs the higher price and would be the less attractive and presumably, you'd want more Permian if you could get it..

Yes. I think the Bakken – that statement I likely would've agreed maybe 18 months ago.

But I think with the Bakken, particularly in the geologically advantaged areas like Myrmidon, where we've seen such a strong response to the higher intensity completion designs, it has elevated at quite frankly on an economic basis, eye to eye with the best in our portfolio..

Right, interesting and then just a follow up I guess, what we were talking about the spill of your assets. One big question amongst everyone about, if you like, the threat from U.S. unconventional growth that you're very much a part of is the non-U.S. non-OPEC decline rates.

Can you make any observations first about that, as far as Marathon and then as far as the globe is concerned? Thanks..

So Paul, I think just from a Marathon Oil standpoint, our international portfolio, operated portfolio is now really largely dominated by one big resource, which is of course, our EG asset, which is a long-life, relatively low-decline asset.

I think that as you expand that perspective outside of Marathon's portfolio, the bottom line is that the conventional world does have a finite decline in those reservoirs.

And I think that's been a little bit masked by some of the long-cycle investments that have FID decisions that were taken really three to five years ago coming to fruition over the last couple of years. So that decline is there.

I think we're going to start seeing that much more visibly as we move forward in time and see this lack of the, I'll say, the longer-cycle barrels coming into the market. And again, presuming continued discipline with OPEC, I think the balance is there, and it's now just a matter of seeing a more consistent drawdown in storage..

Thank you, Lee. And if I could just say that our clients and we appreciate the relatively short prepared comments and the longer Q&A. Thank you..

Yes, we like that model as well, Paul. Thanks for that feedback..

And the next question comes from Brian Singer from Goldman Sachs. Please go ahead..

Thank you. Good morning..

Good morning, Brian..

Since we're going around the horn from shale play to shale play here.

I wondered if you could talk to at the cost inflation profile, cost profiles, and ability to execute that you're seeing in the Eagle Ford versus the Bakken versus Oklahoma from particularly reflecting on midstream facilities in people?.

Sure, Brian. I touched on that a bit about later, if I understood your question, really, guided around inflation and pressures sort of by basin. Similar to the efficiency gains we've seen in the Eagle Ford, where not only are we drilling record pace wells and a more – higher fraction of the wells, hitting that 3,000-foot per day mark.

The Bakken team also delivered three pacesetter wells early this year. First one in the first quarter, and a couple in the second quarter. And we're seeing efficiency on the drilling side pick up materially and on the frac efficiency side across these basins. The Eagle Ford pump record stages per crew in the month of March as well.

We do see as we're standing up new rigs and new frac crews, a little bit of a learning curve at the start, but we're making good progress in all three basins, and quickly getting them to pace with our more continuous operations. So we've been successful in offsetting the majority of the inflation that we've seen to date.

There's still going to be work to do there and teams are focused.

A couple of specific examples where we're changing the completion recipe to eliminate some of the higher cost elements of the design, changing the well design in the Bakken, which eliminates the need for a tieback string and saves a number of operational days, not seeing any difficulty in sourcing materials.

We're also focused on the commercial side with unbundling some of the services, doing some direct sourcing of sand and fuel and other services. So it's a full-court press by all of our asset teams to protect the margins that we worked so hard for during the last couple of years..

Thanks. And then in the Eagle Ford, you highlighted a number of strong 30-day rates in the Guajillo south area. I wondered if you could more broadly talk to what your latest thoughts are on spacing, and then whether the types of rates that you're reporting here are what we should expect more broadly over the Eagle Ford program..

Sure Brian. We've got an extensive position across the Eagle Ford, as you're well aware, 150,000 acres-plus, and spread out across a few counties there and through a few different phase windows. But we are moving as a base design to this – we have moved as a base design to this 2,000 pound per foot on 200-foot stage spacing in the oil window.

We're seeing a nice uplift from that in the early days, and we're getting more run time on that and seeing some of that hold in pretty well. Extremely encouraged by the extension of that down to the Southwest here in Atascosa.

We'll have a number of additional pads coming on to try to confirm those results, but I would say, pretty consistently seeing uplift benefits from that higher intensity completion design. Continue to trial like we did in the Franke May, even higher intensity, which was like 2,500 pounds per foot. So we're encouraged.

Like to get a little bit more production history behind us in this area down to the Southwest in particular and a few more pads to confirm that. But very encouraging early results and we would expect to be able to repeat that..

Great, thank you..

Our next question comes from Pavel Molchanov from Raymond James. Please go ahead..

Thanks for taking the question. As I look at your CapEx spend in Q1 and the increase in full-year guidance, it looks like a very backend loaded picture.

So is my math right that you can be spending around $750 million per quarter by Q4? Is that accurate?.

Yes, that's very accurate. I mean obviously, the first quarter, we were in a bit of a ramp up phase. And so capital was on our plan, but obviously lower than what the ratable spend rate is going to be for the next three quarters, because we're really now hitting our stride, we're bringing completions on now.

We're really starting to hit the pace of true development that we thought we would for the remainder of the year. So you should think of that $2.4 billion budget now being pretty ratable across the next three quarters..

Okay, understood. And as you've three months ago, talked about your kind of 15% to 20% long-term target growth rate at $55 WTI, obviously, today we're at 20% below that.

How long do you have to see oil prices below let's say sub-50 before you decide to pull back on your growth trajectory?.

Yes. It's hard to give a firm timeline on that. But the way I would describe it is, is we would have to see that sustained lower pricing, and that pricing supported by the fundamentals we observed in the market, i.e. it's supported by supply and demand and storage fundamentals, not just technical trading.

And so we're not going – we're very wary of adjusting our full-year plans on the day-to-day fluctuations in oil price. Very difficult for me to see what has fundamentally changed, for instance from this week to last week from a fundamental supply and demand standpoint.

So we would have to see a sustained lower pricing in concert with the fundamental saying that that's now where the market sits before we would start taking adjustments and modulating our spend. The good news for us is that we can respond very rapidly and very effectively in the event that we observe that set of parameters..

All right, very clear. Appreciate it..

Thank you..

Our next question comes from Scott Hanold from RBC Capital Markets. Please go ahead..

Yes, thanks. Good morning..

Good morning, Scott..

Could you discuss a little bit on your, I guess delineation plans? What is the needed yet to delineate in the STACK? And maybe I'll just throw my follow-up question at you right away too. When you look at big picture, you talked about two rigs needed for lease maintenance in the Permian.

Could you just discuss what that is for the STACK, and maybe a couple of others just to give us a sense of what the sort of base lease maintenance is versus discretionary drilling going forward?.

Sure, Scott. I'll take the first one on delineation plans in the STACK. I would say what we're keenly focused on is making ourselves ready for full field development in 2018, where the majority of our activity is going to be on pad drilling.

And so we've got a number of infill tests and pilots that we want to do to optimize well spacing in the Meramec across that. We have been doing some additional delineation to the south and to the east, pretty small data set at this point, but fair to see like you would expect with any delineation program, some mixed results there.

We've got a number of other things that we want to test, both to the south and the east in terms of completion optimization, artificial lift and flow back optimization. But the majority of our activities are really focused on prepping us for full field development in 2018 in both STACK, where the most concentrated activity will be, and SCOOP.

I mentioned earlier on Permian in terms of leasehold protection, nominally two rigs to hold the valuable leasehold there. I think we've talked about three in the STACK combined between the PayRock acquisition that we made last year and some of our legacy leasehold position there.

So that's the type of near-term rig activity that we'll have devoted to those lease protection..

So generally, what I'm hearing is we roll into 2018, I mean the vast majority of your programs are really going to start to look much more developmental.

I guess the Permian will still going to be a bit of a work in process, I would assume, but it seems like in pretty much the other three areas, pretty developmental, is that fair?.

Yes. I think, Scott, that's very accurate. I think the only caveat I might put on that is that clearly, in the STACK and the SCOOP, we're talking of moving into development mode in the major primary targets, Meramec, Woodford and potentially, Springer as well.

And suffice to say, there's still a lot of other potential there than we see in the other zones. But in those primaries zones, absolutely we're moving into development phase in 2018.

As you rightly state, Northern Delaware is still a bit earlier, but we're going to look to accelerate up that curve as quickly as we can using not only our own information as we get into the second half of this year, but certainly, leveraging what is a tremendous amount of industry activity.

I think currently across Eddy and Lee County, there's about a little over 30 rigs running..

I appreciate the color. Thanks..

Our next question comes from Bob Morris from Citi..

Good morning, Lee and team..

Hey, Bob good morning..

Good morning. Some nice results on the Yost pilot that you announced this morning. You now have a peer that's drilled a pilot with 2-mile laterals in the normal pressured oil window here and certainly, on a per lateral foot, the Yost is cuming more over 60 days, although it's a little bit higher proppant loading on your pilot.

Can you tell us again just why you think the sort of laterals are the better way to go here, and sort of now that you've got a peer comp there, whether that reinforces your view or kind of maybe has you thinking a little bit about the longer laterals, or why just you think the shorter laterals of the better way to go here?.

Sure, Bob. As you said, the early results, and we do have to keep in mind it's early, but the early results would suggest the combination of shorter laterals in our completion design is yielding a bit better productivity.

That's consistent with what we saw in earlier wells, where the single laterals, parent wells where the single laterals were competing favorably. And in many cases, from a returns basis, which is really our focus. We're outperforming the extended laterals. So we don't see anything to date that would disqualify that thinking.

We'll continue to watch it and test different concepts. But at this point, we believe the combination of our completion design and single laterals is the way to go..

And then maybe, I would just add, too, Bob. We're going to go with the lateral design that we think generates the highest return. And so consequently, if you look at our completion design in the volatile oil window, we are looking at and we have been using and completing XL wells.

So we're kind of – we're a bit agnostic on lateral length, we're more focused on returns and value generation. And it's great to have this 40 IPs, but at the end of the day, we're really going to be returns-driven..

Certainly. That makes sense. Looking at the last two quarters, again, in the Meramec area, you reported some wells that were outperforming the 940 MBOE-type curve by about 30%. On the Yost pilot today, they're tracking right on that 940 MBOE-type curve on the 60-day cumes.

Any reason why the pilot's right on the type curve where the single wells you report the last two quarters were exceeding that type curve?.

I don't think there's anything that we would point out as any long-reaching conclusion on that, Bob.

As with all of these plays and as with all type curves, there's some variability around the average type curve, which is what we put out and what we would expect for a larger program basis and so there are some variability in geology across the play, and probably, would characterize it more to do with that than anything else at this point.

We're in the early days with only two full section infills in the black oil and more optimization to be done. So I don't think any long-reaching conclusions could be made from that data set..

Okay. Makes sense. Thanks and congrats again..

Thank you, Bob..

Our next question comes from Roger Read from Wells Fargo. Please go ahead..

Thanks. Good morning..

Good morning, Roger..

A lot of stuff has been covered. I guess one thing to ask about. Tom, you made the Northern Delaware acquisitions, you referenced that there would be some swaps and other kind of acreage exchanges.

Just wondering – I know it's early, but kind of where are you in that process and what should we look for? And is there desire to just generally expand that? Or is it really to think about kind of the equivalent current acreage and just working to get a more cohesive set of acreage?.

I think right now, Roger, I would kind of classify it as really the latter. We're really trying to further consolidate our operated positions to the extent that we can get more capability to do longer laterals as well in both the Bone Spring and the Wolfcamp, so that's really our focus.

The good news is that there's a very cooperative operator group in this area in of core operators that have the same interest. In other words, they have the same drivers as we do to try to drive that consolidation.

So even though we're in the very early days, rest assure that the asset team is already focused on the opportunity to continue to consolidate and core up our acreage position there. But in terms of overall scale and scope, obviously, we're very happy with the position we've established through the two acquisitions..

And what do you think the right – what would be your target length for laterals out there? Is it the 10,000 foot, the way we should think about it? Or it might be more reasonable to say around 7,500 foot or something along those lines?.

Yes. I still think it's early days, Roger. Certainly, there appears to be some enhanced economics. We're certainly stepping out to the 7,500-foot length. We'll just have to see.

Even though there's a lot of activity, we still don't have a lot of horizontals on the ground out there that are testing, not only lateral length, the completion designs, spacing designs. So I think it's still a bit too early to draw any direct conclusions, but certainly having the optionality to push lateral length out further is desirable.

When we talk about our Northern Delaware acquisitions in the risk locations, we said, about half of our risk locations were amenable to longer laterals. And we would clearly like to drive that number higher to have that optionality in the future..

Okay, great. And then just one follow-up.

You mentioned the $161 million of EBITDAX out of Equatorial Guinea for Q1, is there a tax leakage we need to consider on bringing this back to the U.S.? Or is that a pretty close to a one-for-one kind of ratio?.

Yes. It's really a one-for-one ratio. This is Dane. We have ample tax attributes to enable us to move cash around the globe without incurring any tax leakage. I mean the same tax in the U.S. from E.G..

That’s great. Thank you..

Thanks Roger..

Our next question comes from Jeffrey Campbell from Tuohy Brothers. Please go ahead..

Good morning and congratulations on the strong quarter. Lee, thinking about your earlier remarks on operating in four basins. You've already mentioned Marathon completions and potentially longer laterals, implying potential upside for prior operations in the Northern Delaware Basin.

I was just wondering if you see potential for any further improvements, for example better zone landing or maybe less drilling time to total depth..

Absolutely. I think as we look at where the Northern Delaware sits on the maturity cycle, there is an immense amount of running room in not only improving the productivity of the completion designs, but also driving costs down on the wells themselves.

I mean, as we compare and contrast the designs for instance, the BC operating was using to the designs, that we will start trialing really in the second quarter, we just see a lot of running room there and a lot of opportunity for further optimization. It's very early.

We're anxious just like you guys are to get out there and get busy and get our own designs in the ground. But I think we're just starting to really see the potential and the learning curve in Northern Delaware, like I said, both from productivity as well as a capital efficiency standpoint..

Okay, thank you. And then as a follow-up, thinking about your references to impending multi-well pad designs mainly in the Northern Delaware Basin, your various Kingfisher test show the Osage underlying.

And I was just wondering if it turns out that the Osage proves commercial in some of those areas, is there any concern regarding returning to your existing pads you drill that interval?.

Yes. Thanks, Jeff. As you note, the STACK has multiple perspective intervals, and the Osage is emerging. There's very few tests that are showing STACK, Meramec and Osage combined development, it's something we're going to have to study. We've got extensive data sets to look at the rock mechanics of that.

It's not something that we've trialed yet, and I'm not aware of other trials of any extent to that. So it's something we'll have to evaluate and study over time. But there are also areas with Woodford potential underlying the Meramec. So we can expect to see over time multi-bench development there, but it hasn't been the near-term focus..

Okay. And the reason I asked you this is because even in the Permian Basin, you have some operators that are moving towards this multi-well mega pad kind of model. And then you've got others that just go in and drill all Wolfcamp base until they get them done, and then they go and do the Wolfcamp base and so forth.

So I just wondered if there was any geological constraint to taking that lateral approach in the STACK, and it sounds like there's not..

None that we're aware of at this point that it's certainly going to be somewhat basin-specific.

And of course, in the Permian and in the Northern Delaware, we see up to 6,000 foot section there and individual benches of several hundred feet, in some cases, and then good vertical separation between that and the next bench, so even less likely that that's going to be an issue for many of the benches in the Northern Delaware.

As you get closer in vertical proximity, then it needs to become more of a consideration..

Okay, great. Thanks. I appreciate the color..

And our next question comes from Arun Jayaram from JPMorgan. Please go ahead..

Yes, good morning. I was wondering if you guys could – it's been about a year since you guys announced the PayRock acquisition.

If you can maybe go through and maybe summarize some of the delineation activities, and how you think the acquisition was measuring up to your expectations thus far?.

Absolutely, Arun. We've been releasing a number of wells over the past few quarters, and I think the Yost infill would be the most recent in the first full section infill test in the black oil window that we've delivered, which is hitting early expectations right on the type curve.

We've released a number of wells in the core that are at or above the type curve. And so I would say, we're very pleased with the results that we've delivered there.

As you might guess, when we did our evaluation for the more untested or less delineated areas, we valued them appropriately, and so a little bit of higher variability in those results is not unexpected either. So we're still very pleased with acquisition.

We're pleased that the Yost infill is confirming our base-case assumption, and with the additional pilots that we have later this year, we'll be testing higher density and it seems that we'll be pushing in that direction..

Great.

Then just my follow-up, the fact that you guys are now in four different key shale basins, does that provide, you think a benefit as you deal with in a major service operator's just given the more some of the challenges we anticipate or likely to see in terms of the supply chain?.

Yes, I think it does afford us the advantage of scale. It also provides us some optionality in the way we approach our commercial discussions as well.

We're able to actually share term across the basins as well as alter, say, rig specifications because we take a fleet management strategy versus a basin-centric strategy, and so being able to apply that scale when you're running a 20 plus rig program is very important.

And obviously, we get the attention of our service providers because of that scale and scope..

Great, thanks a lot..

Thanks, Arun..

Thanks, Arun. End of Q&A.

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

Well, thank you again for your questions today and your interest in Marathon Oil.

We believe our strategy of focusing the business on profitably growing production from our high quality inventory and four of the best oil basins in the world while maintaining a strong balance sheet with a competitive cost structure positions us very favorably to outperform the competition in 2017 and beyond.

Thank you very much again for joining us today and that concludes our call..

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