Zach Dailey - Director of IR Lee Tillman - President and CEO Mitchell Little - VP of Operations Dane Whitehead - EVP and CFO Tom Hellman - Regional VP, Permian.

Ryan Todd - Deutsche Bank Securities, Inc. Guy Baber - Simmons & Co. Doug Leggate - Bank of America Merrill Lynch Evan Calio - Morgan Stanley Paul Sankey - Wolfe Research, LLC Pavel Molchanov - Raymond James & Associates, Inc. Jeffrey Campbell - Tuohy Brothers Investment Research, Inc..

Welcome to the Marathon Oil Corporation 2017 Second Quarter Earnings Conference Call. My name is Collette, 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 Collette. Good morning, everyone and thanks for joining us today. Welcome to Marathon Oil second quarter 2017 conference call. I am Zach Daily, Vice President of Investor Relations.

Also joining me this morning is 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'd 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 subjected to risk 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 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 certainly been an ever-present feature for the last few years. Our view is that well, supply and demand continue to come into balance, the storage overhang has been more stubborn than initially expected, and despite recent draws, it remains the keep proof point for more stability.

Additionally, there remains uncertainty and OpEx 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, our low-cost structure, a relentless focus on execution excellence. Maintaining flexibility in our capital allocations and ongoing commitment to portfolio simplification and concentration. All of this is designed to deliver long term value and returns to our shareholders.

There is little doubt that the current environment test has all of this preparation and underscores financial discipline that we are well equipped. In the second quarter, we achieved outstanding operational performance across the portfolio.

We deliver on our commitment to resume sequential production growth in the resource place 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 that 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 oil performance and continued gains and efficiency while also improving results in the oil window farther West.

We returned the Bakken to sequential growth and delivered impressive results from our first two 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 three rigs, brought on our first MRO design completion job and are driving to optimize the plan of development. Our program in the second half of the year is designed to see that effort.

We're also very pleased to be joined by our Permian Regional Vice President, Tom Hellman. We began 2017 with some key question, some key uncertainties embedded into the assumptions that formed our capital program. An Oklahoma program, that was heavily weighted toward delineation leasehold and infill spacing.

Bakken program seeking to test the response of the Hector area to high intensity completions, and 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 BTI, which we placed originally at $55. We now have more clarity.

So, with just over the half 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 poor four 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 well to sales than in the first half of the year. For the resource plays, Eagle Ford's efficiency and productivity improvement have us on track to hold production on flat sequentially from second quarter levels, which is better than we'd expected.

And Northern Delaware has successfully ramp to its three-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've gained from the first half of the year.

These include improvements in new well productivity better than expected [Carian] 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 state 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 resources plays will move from 20% to 25%, to 23% to 27%. With the confidence that we will made 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 to the second half of 2017 represent a transient somewhat high watermark for outspend, as CapEx is a bit out of face with the operating cash flows it ultimately generate. 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 more than 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 place expected to account for a more significant proportion of the total production mix.

This shift delivered 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 50. We continue to may considerable progress with portfolio management.

In the second quarter, we close 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 and four as the lowest cost, liquids rich U.S. resources 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 tempered by the uncertainty of the macro but are untapped by our confidence and our balance sheet, the quality and scale of our resource, our flexibility and capital allocation, and our demonstrated continues improvement in efficiency and productivity.

At the heart of it all, 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..

Thank you. We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Ryan Todd from Deutsche Bank. Please go ahead..

Great, thanks. Congrats on a great quarter..

Thanks, Ryan..

Maybe if I could turn out with capital and cash flow.

You largely covered cash outflows have been operating cash flow on the first half, how do you think about balancing spend in the 2018? How much would you be willing to outspend in 2018, so the prices were lower 40 or 45 in the few reduced activities? Where would the reductions likely take place?.

Let me starts off Ryan by saying, our objective and we're still on 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 kind of low 50 kinds of WTI levels. However, if we need additional flexibility or adjustability, we have ample tools available to us to adjust to what the micro does deliver..

Okay.

So generally, targets time within cash flow, but a little bit of flexibility to swing either way dependent on the situation is that, how we should think about?.

Absolutely, we're -- obviously we are not here today to talk about 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 may be in the Bakken, you had a couple of really strong wells in the Hector area with enhanced completions there.

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 two Hector wells with our enhanced completions designs that we had kind of proven up in the Myrmidon area. This year, one of our objectives was to extend that down in the Hector, those first two wells have come on strong. I think average IP between the two is about 2500 BOE a day.

And we have got a number of additional trials as we laid out in the earnings release. We are going to extend that across the rest of Hector moving from kind of North West to the East. We've got an additional five pilots and about a third of 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..

Great, thank you..

Thanks, Ryan..

Our next question comes from Guy Baber from Simmons. Please go ahead..

Good morning, everybody and congrats on the strong results. Lee, I am just trying to better understand the improving cash flow profile on overall just resilience of the overall portfolio.

How that’s evolved given well productivity, capital efficiency with 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 may be your portfolio need especially in the U.S.

resource plays to hold that level of production relatively flattish..

Yes, Guy, Well, I think you hit upon 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 three of those key areas which is efficiency, new well productivity as well as just the base performance, our base business really the [Carian] from 2016.

So, we learned a lot in the first of the year. As we take those leanings, we obviously build those in and integrated at the end of the second half of the year plan. And as we move forward looking at 2018, well obviously take not only first half, but second half year results and integrate that as well.

All of those things that we'll contribute to continuing to drive our overall enterprise level kind of if you will breakeven cost 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 number is going to be well south of $2 billion.

And we are 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 may be where specifically you're seeing those efficiencies on that efficiency for 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 equipment, but actually increasing them is a function of the fact that we've simply won 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 vest that Hector area.

Similarly, in the Eagle Ford for instance, we had our strategic objective of pushing a bit farther to the West and 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 pilot.

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 turn deaf to the macro and the impact 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 some of the highest efficiency and highest returns being generated.

And my compliments to both of those teams that you are seeing it not only on well productivity, in other words what the Wells deliver, but also on long 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..

Very helpful and very clear. Thank you very much..

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

Thanks. Good morning..

Good morning..

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

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

Graced up. So yes, 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 you asked this question every quarter, but your type curves are clearly dated relative to the stellar results that you had.

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 the implications of the derisked inventory in the Hector if you could help us with that? I know it's only two wells, but I guess you've got five more in the second half with my [elbow shot], but any color on those two aspects and I've got up a quick follow-up, please..

Yes. Well certainly on that the Bakken area, we continue to be very encouraged from the results there and what we try 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 pads in 2015, such that the data set 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. We're focused again could look at the real data and draw their own conclusions from it.

And due course, we'll take adjustment 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 North-West area, we've got only two wells that's far we've brought to sale.

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 full acreage position and whether about the third 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 to as much of that 120,000 acres as possible..

If I could just to clarify to make sure it’s clear, those five additional pads in Hector, not five additional wells, so it’s about the third of the wells to sales in the second half..

Yes. Good point. Thanks Mitch..

That’s helpful, maybe I'll keep my follow-up as point of clarification and I guess I mean, Lee, obviously completely transformed this portfolio, but the guidance you gave I guess a year to ago the 10% to 12% of 55 now coming down into the 50’s.

I just want to clear, what are you assuming in the type curves for that guidance, is it that dated type curve or is that the current well performance. I am just trying to get a handle on where the risk - the upside risk I guess is, so how your guiding as on what you can do at 50..

Sure, what obviously internally Doug, we are going to take our best risk view of the current production data and incorporate that into to our forward outlook. But it is still going to be a rest of you based on our confidence level and the data set 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’ve provided in the market. And we are clearly going through the planning process today and we will take new data into that process not only for 2018, but for the long-term view as well..

I appreciate the answers, Lee. Thanks again..

Thanks, Doug..

Our next question comes from Evan Calio for Morgan Stanley. Please go ahead..

Hey, good morning guys and good results.

You raised your production guidance as noted while reducing CapEx and the number of completions versus your original 2017 plan I mean if you guys lowered well count assumptions, are you still ramping to 25 and on the budgeting comment if you had to reduce activity to stay close 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 the kind of part and parcel of our plan.

I think the positive is that we built that plan on a $55 deck, we're now of course in a more of upper 40, lower 50 kinds of world and we feel like we can still deliver in limit and outspend the amount to say $200 million to $300 million this year.

So, that was all part of the plan with the loss of OSM cash flows and obviously with the new investment in Northern Delaware, that was part of our original plan. When we think about our activity levels, we tend to look at the metric which is the best measure of output which is wells to sales.

Rigs, we are going to optimize, frac cruise we are going to optimize, we continue to gain efficiency across both of those areas of our business.

So, we really look at well to sales and in an absolute sense, we are 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 are going to be running Eagle Ford at a pace in 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 for the year then it was in the first half of the year as we ramped up there.

In Northern Delaware, we're really on a three-rig run rate there, because of the work that we are 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 fit in terms of the pace of driving our infill programs such that we have the opportunity to incorporate learning in real-time. So, it’s those factors really that are driving our wells to sales if you will in the second half for the year.

So, we think of it more as wells to sales story versus a rig count story..

I appreciate that color. And my second question, positive on Hector was governing and congrats there.

On the Hansen infill wells which IP-ed 35% to 30% below the parent of the same section and now is it similar drop off parent to child yields, to what extent is Hansen's performance representative of what we should expect in the black oil development, black oil window under full development and what can you do to mitigate the drop off and performance from parent to child and what we might see later this year and Eve?.

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 Hansen continues to support kind of our six wells per DSU base case that we had for the black oil window. But I will stress, it is still a very limited data set.

Hansen is only one of three or four infills in the Meramec black oil window. So, we're still testing a lot of variable.

I mean these truly are a pilot, 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 IP 30 gain.

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 often times, 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 volatile oil window, we got the black oil window, they are 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 two of our pilots now on the ground. But we continue to be obviously it supportive of where the black oil Meramec program is going to take it, but it still very early days. With that, Mitch..

Evan, I'll just try to build on to that a little bit and maybe start picking up from one of lease last point which the Hansen section, those where 4,600-foot laterals completed well cost of about $4.3 million.

And so, as we Lee rightly point out, that's not a ubiquitous play, there is 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 [Caine], Woodford, or Bakken or Eagle Ford, we're in the optimization phase and the fact pattern that we see here and the number of trials that's going on is pretty consistent with how those plays built up and ultimately, we crack the nut.

These were the that kind of technical challenges that our teams loved to solve and they have 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 your other questions, the Yost was our first attempt in the black oil infill, we started with kind of our baseline conclusion design there. We learned some things about well interactions and we've modified completion parameters on the Hansen.

In terms of fluid chemistry, fluid mix and the use of diversion, we're encouraged and not to mention tighter spacing test if you recall and as we try to lay out in the slide, this was really multidimensional pilot and on the western side of the section, we actually tested 660 foot spacing versus about 900 foot spacing on the Hansen.

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 Hansen to help us better characterize the fractured geometry, through use of electromagnetic proppant, micro-seismic 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 we'll help concentrate the energy closer to the new wells. And we look forward to seeing and how quickly and how materially, we can optimize as we go forward, particularly these direct offset wells..

And so recent direct change in the Eve..

Absolutely..

In the back half of this year. Okay..

Absolutely..

And even that's part of the reason why cadence right now is very important. Because we want to make sure that we've 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..

Very helpful. Thanks guys..

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

Hi guys. The call I guess right it has all been about the U.S. I was wondering if this potential for you lead to - to go back to the restructuring and focusing strategy that you previously employed to get today. Obviously, what I'm thinking about is the disposal of international. I do think you'll get rewarded for even more focus.

And then sort of a follow-up, can you talk about how dividend and dividend growth fits into this. Because again the way the company is moving suggest that it'll be more about growth and resource development then it would be about for example a strategy to have a rapidly rising dividend. I think we would save it lastly, but I'd -- thanks..

Okay. Thanks for expressing our preference. Let me start maybe with portfolio management. We will never be done with portfolio management. It's just something that we need to do as an AMP company. We've had a very strong focus on that.

Our corporate development team has just done an outstanding job and implementing our non-core asset program which really culminated in some ways with the exit from 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 asses that are outside of kind of our core assets, which are really our U.S.

resource plays and Equatorial Guinea are really the two 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 aside 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 you second question around dividend growth, in 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 scrutinized that to 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 been 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 that as you said that did express preference, but I'm not 100% convinced as long as you are doing what you say you're doing, which is profitably growing I guess at least to adding to resource. But anyway, I thanks to your folks..

Yes. Thank you, Paul. Appreciate it..

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

Thanks for taking my question. 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 your saying your BoE will be growing in-line with your liquids number given that gases back below to $3 level.

Is there a sense that maybe you should be kind of deemphasizing 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 in our four basin is largely liquids biased with the exception may be some of the gas area, most of the gas production you are seeing is associated gas outside of our international business where you have EG but we like our Oil and liquids waiting we felt that was a very important and specific that our growth metrics were on both of BoE as well as an oil basis to give that priority on that mix going forward but that mix it's going not use to continue to stay strong.

We like our liquids biased and we are going to continue to support that liquids in all biased..

Okay. Then look at you hedge book, your hedge out of decent amount may be 30% of sale of your domestic oil production in second half of this year, it's kind of tapers off into 2018 or you looking to add more hedges particularly as the curve kind of get back into contango..

Hey Pavel. This is Dane.

Yes, you may have seen in our disclosure in our slide that we recently added about 20,000 barrels of day of count 2018 three well oil positioned at 43 by 50 by 55 and we certainly are going to keep methodically working our risk management activities both from the balance of 2017 and 2018 and as we go forward we will start looking into 2019 as well.

I think we have well established team and set of practices now on and when we see market opportunity created by Raleigh particularly in oil but watch gas and NGLs as well expected to continue to lead in to those positions..

I think we are going to be in a defensive hedger where we try to get in there and protect the key aspects of our investments program but at the same time going back to my comments, we are on liquids waiting.

We wanted to actually make sure that we preserve that upside potential for our investors as well that’s critically important to go forward business model..

Understood, all right. Congrats on the numbers. Thanks guys..

Thank you..

Once again if you do have a question please star one. Our next question comes from Jeffrey Campbell from Tuohy Brothers. Please go ahead..

Good morning and congratulations on the quarter.

Lee on slide 14, I was impressed that Marathon already conducting an ambitious Delaware Basins and delineation test at Cyprus, but I wanted to point out a 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 Third Bone Spring.

With the illustration, additionally shows new wells in the Second Bones Spring, so I just wondering if you could add some color on to how the Second Bone Spring fits into your overall Cyprus thought process..

Jeffrey, this is Tom. Yes, nice catch there. Early days right after even the acquisition even with BD team intact we already talking about this infill pilot and right away we looked at that X-Y for practical well spacing of eight wells a section and we were going to add some signs to this and we are going to be very aggressive on the completions.

And while we are working with that, we also recognized of the Second Bone above that, it looks great as well and we wanted to add some more wells in the areas so that’s a four well per section basically spacing trial above it and it actually adds a little more logistics to scale this.

So, we're also testing that our logistics and learning curve on the drilling on the completion side, because we went off and we have a dedicated crew now that'll come in and [do that on the] fact side, with much better pricing. We've even self-source for our own stand for that. So, all of that came into the test itself at infill well spacing.

And we're also going to pick up a Third Bone well and lower Wolfcamp as you can see for some delineation..

And kind of staying on that theme of the delineation and multiple well -- multiple zone potential, also in the Permian Basin also in the Delaware Basin, many producers are moving towards the model of completing all the locations of a given zone or even several zones that wants to avoid well interference and enhance efficiencies.

I was wondering if you're going to be testing any of those kinds of concepts with this pilot and maybe others and also, I was wondering if you think that there is - not appropriate for okay, 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 is still kind of in the early phases.

This is really our first foray in getting out and testing some of our assumptions that we had built in 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 picked it, and we just completed two wells in the last quarter.

This was really an acreage pickup by us. We're still - I would say accessing 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 in 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 sub surface risk 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 completion 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 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..

I appreciate that color and I think that's make perfect sense. Just a follow-up again.

Are you - is this kind of thinking appropriate for Oklahoma Resource particularly thinking to have some pilot and any other pilots you're doing that or is there something unique and Oklahoma 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 is a bit more development there. You have a bit more leasehold offset to you as well. So perhaps a pure kind of application and 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. As are there some implicit advantages even if you have a parent well in place to going in and doing you’re - if you will full development pattern all at one time obviously coming back at a later point present some unique challenges.

So, I think the logic can certainly be applied in Oklahoma..

Okay. Thanks very much. Appreciate it..

Thanks, Jeff..

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

All right. So, thank you very much for joining us today. It was a fantastic quarter. I want to again thank all of our teams and our employees that contributed to this great outcome. We continue to believe that the robust model that we've develop with the 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..

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