Zach Dailey - Marathon Oil Corp. Lee M. Tillman - Marathon Oil Corp. Thomas Mitchell Little - Marathon Oil Corp. Patrick J. Wagner - Marathon Oil Corp..

Evan Calio - Morgan Stanley & Co. LLC Kalei S. Akamine - Bank of America Merrill Lynch Paul Sankey - Wolfe Research LLC Brian Singer - Goldman Sachs & Co. Pavel S. Molchanov - Raymond James & Associates, Inc. Scott Hanold - RBC Capital Markets LLC Jason Gammel - Jefferies International Ltd. Roger D.

Read - Wells Fargo Securities LLC David Martin Heikkinen - Heikkinen Energy Advisors LLC Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Jeff L. Campbell - Tuohy Brothers Investment Research, Inc..

Welcome to the Marathon Oil Corporation 2016 Q4 Earnings and 2017 Capital Program Conference Call. My name is, Cynthia, 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-answer session. Please note that this conference is being recorded.

And I will now turn it over to Zach Dailey. Zach, you may begin..

Thanks, Cynthia. Good morning, everyone. And, thanks for joining us today. Welcome to Marathon Oil's fourth quarter of 2016 earnings and 2017 capital program conference call. I'm Zach Dailey, Director of Investor Relations.

Also joining me this morning are, Lee Tillman, President and CEO, Mitch Little, Executive Vice President of Operations; and Pat Wagner, Interim CFO and Vice President of Corporate Development. We released prepared remarks last night in connection with both, the earnings and capital program releases.

You can find those remarks in the associated slides on our website at marathonoil.com. Following some brief remarks from Lee, we'll open the call for Q&A, where we'd request you ask no more than two questions and you can re-prompt if 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 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, and good morning to everyone. I'll make a few brief comments then open the call for questions. 2016 was a year about delivering on our commitments, and delivering on these commitments despite an extremely volatile commodity price environment that saw oil trade below $30 a barrel.

We set a clear overarching goal for 2016, to live within our means by balancing CapEx and the dividend with operating cash flow and proceeds from our non-core asset program. Not only did we achieve this outcome, but we did so inclusive of our material STACK acquisition in Oklahoma.

Our success was predicated on capital discipline, portfolio management, operational execution and a relentless focus on our costs. We ultimately finished the year at $1.1 billion of CapEx, down $300 million from our original budget, while exceeding the mid-point of our production guidance.

And within that reduced capital spend we exited the year running 12 rigs in the U.S. resource plays, gaining valuable operational momentum as we look to average 22 rigs in 2017.

We executed on all of these fronts in 2016, while ending the year with $2.5 billion in cash and $5.8 billion of total liquidity, positioning the company strongly for 2017 and beyond. Last night, we announced a 2017 capital program of $2.2 billion of $2.2 billion, with over 90% allocated to our high return U.S.

resource plays, and roughly balanced with about a third to Oklahoma, Bakken and the Eagle Ford. Our top capital allocation priorities remain STACK leasehold, delineation and down spacing in Oklahoma, as we prepare that asset for full-field development in early 2018.

We'll more than double our Oklahoma rig count from six 6 today to about 13 by the end of the year to achieve that. Beyond Oklahoma strategic objectives, we'll be ramping Bakken activity significantly, with two-thirds of their capital dedicated to bringing our high-return Myrmidon area to development mode this year.

We'll build upon last year's success from high intensity completions that generated basin-leading well results from both, our West Myrmidon and East Myrmidon acreage and take advantage of scale efficiencies.

We plan to extend the application of higher intensity completion techniques to Hector, where we have a larger footprint of about 115,000 net acres. Even with modest uplift, the Hector program is expected to meet or exceed East Myrmidon returns.

And, finally, the Eagle Ford will become a substantial free cash flow generator as we keep activity at maintenance levels in 2017, while protecting our economies of scales and enhancing efficiencies even further.

Rates of return in Eagle Ford are very compelling, as we continue to focus on the high margin oil window and benefit from very low completed well costs.

This capital program accelerates quarterly growth in resource plays to the second quarter and achieves exit-to-exit oil and boe growth of 15% to 20% in the resource plays, while [audio skip] (05:25) cash flow this year at $55 WTI.

2017's momentum positions us strongly for the future and places us on track for 2017 to 2021, oil and boe production years, of 10% to 12% for the total company. That includes Oil Sands, but excludes Libya, and increased U.S. resource play CAGR guidance of 18% to 22%, also, for oil and boe.

We plan to achieve all of these growth rates within cash flows each year, inclusive of the dividend at flat $55 WTI. We believe that a business model built around sustainable, profitable growth within cash flows will deliver excellent long-term results for our shareholders. With that we can open it up for questions..

Thank you. We will now begin the question-answer session. . And our first question comes from Evan Calio with Morgan Stanley. You may begin..

Hi. Good morning guys..

Good morning, Evan..

So, you guys raised your long-term U.S. resource growth guidance from 15% to 20% to 18% to 22% – or to 18% to 22% from 15% to 20%, within cash flow.

Can you walk us through the pieces that drove the raise? And given the size of the rig – ramp what you're expecting on the inflation side?.

Yeah. Yeah, Evan, let me kind of address. You know, first of all the 15% to 20% was really calibrated on a very preliminary view of our plan, Evan, so a lot of it was just fully building on our plan, getting the latest and greatest definition built into that plan.

And with that work, we've been able to move that number forward, so we feel very confident in that. I'll maybe offer a few high level views on the second part of your question on the inflation piece. And, then maybe let Mitch chime in with some specifics.

You know, obviously, we have built an inflation in our capital program, and we built that in with, you know, due consideration of being able to be successful at mitigating elements of that through continued secular efficiencies, but there are lot of moving pieces to it.

I mean, we are increasing the intensity of designs, we know that inflation will vary both, by basin as well as by service line. So, there are many, many elements of it. And, of course, we're somewhat reluctant to talk about hard numbers, because quite frankly, we're still out there negotiating with a lot of our service providers.

And, we don't see a lot of benefit in that. But, it is built in. It does match up with our view of pricing and activity. And, I think, we've also done some things on the commercial side that will continue to not only give us some advantages, but also continue to provide us flexibility in the event that we can need to modulate activity..

Yeah, Evan. Good morning. This is Mitch. Just building on a couple of Lee's comments, you know, heading into the year, we built in some protections, locking in rates at or near the bottom on a number of drilling rigs. Certainly, see a bit more pressure on the completion side of things, and less so on the drilling rigs side.

I'd also offer, as we move in to scale in the Bakken and also ramping up activity at Oklahoma, we'd expect to be able to capture efficiencies like we've seen in the Eagle Ford. So, there's certainly an offset there.

And, obviously, with the additional scale and activity, we'll continue to leverage that to make sure that we maintain competitive pricing across all three basins..

That's great. And maybe for a second question. Just want to better understand what drove the equal capital allocation among the three unconventional plays, you know, specifically the increase in the Bakken as a percentage of spending over the Eagle Ford IGOR (10:09) region.

And, you know, were the limitations on the pace of development in each basin? I know you're ruining 22 rigs, average up from 14 rigs, or was it – was allocation strictly returns-driven? Any color there would be helpful..

Yeah.

Well, first and foremost, you know, Evan, as I stated in my opening comments, and I think as we've talked about is, we were going to make sure we achieved our strategic objectives in Oklahoma, and that's around protecting our valuable leasehold, delineation and doing the downspacing and completion work that we need to have at hand to drive that asset toward full-field development in 2018.

We feel that the program we've designed this year allows us to deliver across all of those strategic objectives.

Once we met that, really, the criteria was to look at where we could generate the highest risk adjusted returns as well as continue to capture a scale efficiencies, and that really led us down the path of the capital allocation that you see in the plan.

The Bakken opportunities compete head-to-head with the best in our portfolio, we challenged the Bakken team to really step up last year. They did so, really demonstrated their ability to go head-to-head with even the oil window in the Eagle Ford. And based on that, we struck a balance between those two assets.

With Eagle Ford already operating at scale and very efficiently, we wanted to drive Bakken into more of a development mode, while also seeking to extend the success we saw in Myrmidon to places like Hector, so that was really the high level allocation..

Great. Appreciate it, guys..

Thank you, Evan..

And our next question comes from Doug Leggate from Bank of America Merrill Lynch. You may begin..

Hey guys. Good morning. This is Kalei on for Doug..

Hi, Kalei. Good morning..

Hey, a couple questions from me. So, understand that you guys have a handful of operative pilots planned in the STACK this year. And I'm wondering whether those will be primarily in the Central to Eastern Kingfisher region where you guys have a lot of contagious acreage.

And what I'm really trying to understand is how important those results will be in terms of updating your STACK oil type curve that continues to look too low..

Sure, Kalei. This is Mitch. I'll address your question. And then, Lee can add to it if he likes. But, we're going to be bringing four to five STACK infill pilots to sales during 2017, likely spud a couple more than that.

First one is the Yost infill that we TDed in fourth quarter That's a six-well infill, testing a couple benches and six wells per section there in Kingfisher, and our next infill will also be in that same area. Throughout the year, we'll be testing tighter well density, different landing zones.

We see up to – between four and six high quality potential landing intervals. We'll certainly be optimizing around that, optimizing completion designs, flow back techniques and different stack-and-stagger concepts.

As you said, our core wells continue to perform at or above the type curve expectations, including the Schoeder (14:03) well right in Northern Canadian there that we released this quarter. And, certainly all that's going to be integrated into understanding the longer term performance and the best way to optimize full-field development into 2018.

So, we'll integrate that and update as appropriate..

I appreciate your comments. In the Bakken, it looks like you guys are moving forward with those enhanced completions, which provided strong results, but the range of propane on the go-forward plan look quite wide. You look to be at about 5 million pound to 16 million pound.

I'm wondering, what's the reason behind the variation in that completion design? And, can you talk about whether these improvements can support an expansion in the Bakken inventory?.

Sure. I'll address that one as well. And, the variability in propane, total propant per well is really specific to different intervals that we are developing in the Bakken, whether Middle Bakken or Three Forks, first and second benches.

Typically a little bit lower sand density propant concentration in the Three Forks, so that would represent the lower-end and the higher end as more typical of our Middle Bakken completions, different fluid types.

You know, and as we talked about, we're moving to development mode in Myrmidon, where we've got that 60,000-acre position in advanced or advantaged geology.

Looking to extend that into Hector, where we've got about twice the acreage position and we're applying the same science that we used last year to apply in the Myrmidon area and deliver those basin-leading results. So we got pretty – I've got pretty high confidence in our ability to uplift those wells.

And, as Lee noted in his opening comments, just a modest uplift will move that program up to be very competitive in our portfolio..

Thanks. Appreciate the comments..

And, our next question comes from Paul Sankey with Wolfe Research. You may begin..

Hi. Good morning, everyone. If I could start with a high-level question, Lee..

Sure, Paul..

You've got to that sort of 20% range of growth.

Would you consider that to be a terminal level, whereby we could consider any future cash flow upside to be, I guess, perhaps even rotated into buyback or how do you see the position of Marathon in terms of what the marginal discipline will be from this point, given that you, as I say, once you get to that sort of 20% CAGR, you're kind of hitting a terminal level of growth I would have thought.

Thanks (16:46)..

Yeah. I think, Paul, you know, I still believe that in our model for the five-year plan, bear in mind, that's a benchmark kind of flat $55 WTI. And so, we were optimizing again around living within cash flows to deliver those long-term CAGRs.

We still have the organic inventory, if you will, to put additional capital to work if we were to see more constructive pricing. And, that would obviously be our preference from a shareholder value standpoint would be to continue to look at that.

At some point, of course, you're going to hit a pace of activity that probably would not be supported, and you would have to look at other opportunities for use of that incremental capital. I think, we've been very explicit that, for instance this year, we have cash on hand on our balance sheet.

And we're going to be looking to use that to provide flexibility on handling some of our near-term debt maturities.

Directionally, you know, we'd like to bring down our gross debt and we also want to be able to participate broadly – and resource capture opportunities in the market, particularly large accretive bolt-on, not dissimilar to what we did last summer with the STACK acquisition, so all of those things from my perspective offer incremental value to the shareholder if we meet all of our organic needs..

Okay.

So, what would be the returns basis? For example, the choice to expand rather than to buy in your own stock or once you've done the debt repay down, which I understand?.

Yeah. I think, then it just becomes an economic view. But, I think, given the incremental returns that we're able to generate, particularly in the short cycle U.S. investments, Paul, I feel very confident that those will compete very favorably to alternative uses of giving the cash back to the shareholder..

Got it. And then if I could ask a very specific follow-up..

Sure..

The wells bought to sales in Bakken and Oklahoma, seem a little bit light to us, relative to the way you're ramping up the rig count? Is that – because we would be expecting a sort of backlog or sort of these situations to be building up into 2018? And if so, could you just quantify that what that is? Thank you..

Yeah. Yeah. Sure, Paul. As we ramp up to the higher activity levels, we'll certainly be building some operational inventory towards the end of the year. And keep in mind as well, in the Bakken, we're planning to do up to 25 refracs. Those are not included in new wells to sales.

They would be incremental to that, but you can imagine it as being kind of a handful of pads in the Bakken. And, you know, similar number well count in Oklahoma that we would build just an operational inventory to make sure we operate on the completion side as efficiently as is possible, keeping full utilization of steady crews..

Thank you..

And our next question comes from Brian Singer with Goldman Sachs. You may begin..

Thank you. Good morning..

Good morning, Brian..

First question is a bit of a follow-up to Paul's last question there. If we look at the Eagle Ford, I think, you mentioned that the six rigs puts it into a maintenance mode or maintenance capital.

Does that mean we should expect a generally flat exit-to-exit or should we expect that that would get us or get Marathon some production growth? And similar type question for six rigs on the Bakken?.

Yeah. Well, first, you know, let me deal with Eagle Ford. You know, though we've talked about maintenance activity levels. And, again, we don't do – usually, we don't provide exit-to-exit course on a basin-by-basin basis. But, what I will say, you know, Brian is that the Eagle Ford will participate in that five-year CAGR growth.

As we optimized the 2017 program, the Eagle Ford, at a maintenance level, made sense. We have sufficient inventory though to continue to drive growth in the Eagle Ford in the future. And certainly within that time year window and the Eagle Ford is a component of that longer-term CAGR that we've talked about the 18% to 22%.

On the Bakken, we are looking at an initial ramp-up this year as we get it back into development mode.

And then, I think with respect to the future, we anticipate that Bakken will continue to grow and again participate in those long-term growth rates, but it's probably a little early to start talking about how we might or might not optimize the 2018 plan, specifically, but we expect all three basins to participate in that long-term CAGR..

Great. Thanks. And then, my follow-up is just a strategic one with the focus very narrowed here on these three key resource plays.

Did you feel like you have sufficient scale, obviously, you're due to get to the CAGR that you've mentioned here, but did you see opportunities out there either to expand your positions or swap positions to further add scale within these three areas or are there any other resource areas you're focused on..

Well, we're very happy with our organic inventory and feel confident in our ability across our three basins to deliver on the CAGRs that that we've talked about. Having said that, Brian, we're always looking at potential resource capture opportunities within our three core basins.

I think, that was clearly on display last year with the STACK acquisition. We've done some smaller bolt-ons as well. One of the reasons we want financial flexibility and a strong balance sheet is, so that we can participate in those market opportunities, as they present themselves.

But, in terms of the delivery of the plan that we have described from a CAGR standpoint, we have the organic opportunities to power that..

Great. Thank you very much..

Thank you, Brian..

And our next question comes from Pavel Molchanov with Raymond James. You may begin..

Yeah. Thanks for taking the question, guys. So the International component of your production's still almost half of the total, but it's getting only 10% of the CapEx.

How long do you think you can maintain those International volumes, including oil sands at their current CapEx run rate?.

Yeah. Well, the International business is still a material element of our business. But, obviously, it is also shifted in its significance, not only from a capital allocation standpoint but also from an overall volumetric standpoint as well. The North America segment now is quite a bit larger than our International segment.

And that, of course, is by design; that's where our growth assets are. But, from a cash flow contribution standpoint, obviously, the International segment via our integrated business in Equatorial Guinea remains still a large component of free cash flow generation for the corporation that can be redeployed.

That's even amplified in 2017, as we have come out of a relatively high investment year in Equatorial Guinea with the installation and startup of the compression deck last year. Similarly, OSM with improved performance, both on the reliability side, as well as on the cost side, offers the ability to provide free cash flow as well..

And our next question comes from Scott Hanold with RBC Capital Markets. You may begin..

Thanks. Good morning, guys..

Hey, Scott. Good morning..

Maybe another question on capital allocation. And, just as you look into 2018 and through that 2021 outlook, how do you envision – you know, obviously, you're not looking for too much specifics, but how do you envision the weighting of that allocation going between the three resource plays, right now it's a third, a third, a third.

But, as you look forward over the next few years, where ultimately do you want that to get to by 2020?.

Yeah. Again, we haven't provided a specific projection around that, Scott. But, where we sit today, I would say we have never had a more diverse set of high return opportunities that are competing.

I mean, if you looked at some of our material, where we've given some of those opportunities and the associated indicative economics, we've got a broad suite of things to select from and many opportunities that really didn't even show up on that page, things like the Springer and Oklahoma for instance and condensate in the Eagle Ford.

So, our view is that we're going to continue to look first at delivering on strategic objectives in our plays. To the extent that we meet those, then we're going to look at it from a risk-adjusted return basis and also trying to leverage our ability to generate scale efficiencies. And so, it will be an ongoing real-time optimization of capital.

That's part of the short-cycle business and you should expect to see that that one-third, one-third, one-third is not something that's set in stone. That will move as we move the business over the next five years..

Okay. All right, so is there particular bias? So, I mean, it seems like the STACK that, you know, certainly has got the most, I guess, relative....

Yes..

...upside excitement.

Would that be, you know, just – would there be a bias of getting a little bit more active there?.

Yeah. Well, certainly, as you point out, Scott, it is the basin that is earliest in its maturity cycle and has quite a bit of running room in front of it. So, I would agree that on balance, Oklahoma will be a large consumer of capital allocation going forward in that five-year period..

Okay. Thank you. And as a follow-up question, Libya, I understand the unknowns and uncertainties in terms of what's going to happen there. But, you did get a little bit of production this quarter – this past quarter.

You know, where do we stand today and what could be the potential, I guess, from our seat upside implications if you do get some volumes coming through the year? How much incremental cash flow could you all stand to benefit there?.

Yeah. Scott, this is Mitch. Production resumed in fourth quarter. And, as we exited the year, gross production was up to about – just under 80,000 barrels a day, so little under 11,000 net. It's held pretty steady at that level this far into the year. Certainly, the Libyans would like to ramp that up.

There're some infrastructure issues that need to be addressed, both at the export terminal, some of the transportation lines and some of the inner field lines that will dictate that pace along with just kind of the ebb and flow on the ground there with a political situation. So, pretty hard to project where that's headed.

But today, sitting around 80,000, which is where we finished the year or 11,000 net..

(29:26)..

I think the fact – I'm sorry, Scott. I was just going to say, I think the fact that we were successful like getting a couple of liftings in the fourth quarter, that's a – you know, that's a great signal to us that at least we've been able to generate some cash flow there. I know some of our partners have addressed that as well.

But we view Libya, as a potential contributor of free cash flow assuming that the security situation remains stable this year. We clawed back some of our under-lifted positions, but we would think that we would see some free cash flow generation there..

Okay.

Would you be willing to sort of quantify based on where we're at today, how big that could be?.

Yeah. I mean, it's going to be probably in the $100 million to a couple hundred million bucks in that neighborhood. But, again, it's going to be dependent upon, how we go..

Absolutely. I appreciate that. Thanks..

Yeah. Scott, and I'd just add a couple of comments there. Of course, it's not in our guidance. And our projections of living within our means are excluding Libya. But our interest is the same as the other large international ownership of those – partner in those concessions, but as Lee mentioned, we had two liftings in December.

So we're in a slightly different position..

And our next question comes from Jason Gammel with Jefferies. You may begin..

Thanks very much.

Obviously, activity levels picking up pretty quickly in Oklahoma, I was hoping you could just address any risks to the activity ramping at such a fast rate? And I'm thinking in terms of having the human resource capabilities in place, having full understanding of the subsurface given the PayRock's relatively recent addition to the portfolio and even things like infrastructure constraints?.

Sure, Jason. This is Mitch. As we were building our activity plan and execution plan across all three resource plays late last year, we put a well-defined execution strategy together, which of course address staffing, infrastructure, access to services and all of that.

And so, we're tracking that regularly and we're on or ahead of plan across all of those major objectives. We're not having difficulty in sourcing either human resources or the suppliers that we need to execute that plan. And so, we don't really see that being a bottleneck for us.

On the infrastructure side, we're actively working various aspects of that both, on the crude oil and on the residue gas side. We do see a need in the longer-term – mid-term to longer-term to add additional infrastructure for residue gas takeaway capacity.

And, we also – while we don't have any limitations, we would like to see more of our oil on pipe and are moving in that direction and would expect the majority to be on the pipe when we get into full-field development mode..

Great. That's useful. And then, maybe just my question would be around cash priorities. You clearly – you made very clear the ability to reinvest into the portfolio and that being a priority. But, you've also been very careful about emphasizing that you would be spending within cash flow, including the dividend.

So, maybe if you could just address the dividend, rather you would consider that just to be a number, we should think it as flat going forward or if there's any plan for progress of within the dividend or does the same logic apply as it does to share repurchases? Then, maybe just sneak one more in the back of this because of the write-down of the deferred tax assets, can we assume that you won't be a cash payer in the U.S.

for foreseeable future?.

Yeah. Let me talk little bit about the dividend and maybe Pat can chime in on the valuational allowances that we took this past quarter.

But, from a cash on balance sheet kind of standpoint right now again our number one objective is, as we look back to 2016, was to ensure that we had the financial flexibility to deal with ranges in commodity prices, but also near-term debt maturities, with, again, a goal of directionally reducing our gross debt.

We also clearly want to be able to participate in resource capture if that looks like it may be on offer in the market. And so in that kind of call on those funds, today, we don't really see the value being generated to the shareholder through returning cash in the form of dividend.

But, again, that's a decision that we'll continue to evaluate in the future as we see our business continue to grow..

Okay. This is Pat. As you mentioned, we did take the record valuation allowance of $1.3 billion in the quarter. That was triggered by an expected cum pre-tax loss in recent years. For modeling purposes moving forward in 2017, you should assume that there is no cash taxes in the U.S. and no U.S. deferred tax benefit or expense for the year..

Very clear. Thanks, guys..

Thank you, Jason..

And our next question comes from Roger Read with Wells Fargo. You may begin..

Thanks, gentlemen. Good morning to you..

Good morning, Roger..

Well, I guess, I was going to kind of ask you that cash flow question. So thanks, for taking care of that. I guess maybe, a second way to think about things, given the overall layout here not just for 2017, but the longer term CAGR.

What would you take your foot off to gas on most likely if we don't get the $55 oil price either as in average for 2017 or if we have a speed bump here out there in 2018 or 2019 or something like that? Is it Eagle Ford? Is it Bakken? It doesn't sound like it would be Oklahoma unless things were pretty dire again?.

Yeah. I would say, Roger, that clearly, Oklahoma for us really is a strategic objective to get that asset ready for full-field development. And, beyond that, the other investments in our portfolio are largely discretionary in terms of they are driven by economic returns.

And so, if we felt that we needed to modulate activity, we would do that based on making a reasonable view of returns in addition to looking at the scale efficiencies that exist in the basin. So, it'd be a bit of a gain they call along on how we would approach that. But, we're going to deliver on the requirements in Oklahoma.

And, I'd also maybe point out that, you know, in that scenario things like our commodity risk management through hedging also come into play.

And, we've been very intentional about putting on a defensive hedging strategy that will underwrite the strategic elements of our business plan to ensure that we don't end up in a situation where that – those elements of our plan come under pressure..

Okay. Appreciate that. And then, I guess, a little bit back to the balance sheet, obviously, the plan to pay off some debt this year.

Should we look at future debt repayment as opposed to debt refinance as we see future maturity dates?.

So, I think, what we've talked about, Roger, is that, we want to protect the flexibility to deal with those maturities based on the business environment at that point in time. We haven't really telegraphed whether that means re-fi on some, or pay down on others, or even tendering at some point.

I mean, those are all options that would be on the table, but we want to make sure that we have the flexibility to deal with those in the most efficient manner that we can. And so, that's the way I would think about it. But, directionally, you are correct. We will be looking to reduce gross debt..

Okay. Thank you..

And our next questions comes from David Heikkinen with Heikkinen Energy Advisors (38:49). You may begin..

Good morning, guys. And, thanks for taking my question.

Just thinking about your annual capitalized costs per rig line in the Bakken STACK and Eagle Ford, can you just talk about where that is? And then, with the improved well designs and kind of larger completions, how that changes through the year or are there any changes to that?.

Sure, David. It's a bit more complicated than that, I guess, I would say. And the reason is, coming back to some of the discussion we had earlier on the call. You know, we've got different completion designs for different well types, whether that was in the Bakken. Obviously, in Oklahoma, we've got SL wells, XL wells, STACK wells, some SCOOP wells.

And then in the Eagle Ford, we've got multiple development concepts there depending on the specific areas reservoir stratigraphy, fluid type et cetera. So, I think, you know, what I would maybe point you to back to the Bakken specifically, and Oklahoma to some degree.

As we're moving to the activity levels that we're headed towards, requires us to build a bit more operational inventory than we would have in the past, where at lower activities, you drill it and go immediately complete it to make sure we utilize our frac crews the most efficiently, we need a little bit of operational inventory there.

We've also got the refrac program in Bakken, which is consuming part of the capital up to 25 refracs there. So, it's really hard to put a specific number on a rig line.

And we touched early in the call as well, of course, we built some net inflation offset by some efficiencies in all these basins, but we just don't see value given our ongoing discussions to put a number out there..

Yeah. So $100 million per rig line, rough number $110 million, that includes refracs and some changes in plans. So, that isn't a great run rate is what it sounds like. (41:10) – a third of your capital with six rigs in two different plays is about $110 million; $100 million per play is the simple math..

Yeah, but that's a simple math, I think as Mitch kind of outlined David, it's not that quite that simple..

Exactly..

Of course in Oklahoma you still have a big non-operated slice in Oklahoma, you got the complexity in the Bakken of having a little bit of drill, but uncompleted inventory, probably a bit more than we typically had there by year end coupled with a relatively aggressive recomplete or refrac program in Hector.

And, so there are some moving parts in there to make the math a little less straightforward, if you're trying to search kind of for our capital efficiency number per rig..

Right. That's kind of what I was getting to. Maybe on the other direction....

Yeah..

...just completely, so cash flow plus dividends. I mean, cash flow equals CapEx plus dividend. At $55 oil, it's kind of a $2.5 billion run rate into next year is what it roughly gets into, $600 million in the fourth quarter is our run rate; that matches.

So, is that a fair exit rate for CapEx, around $600 million?.

Yeah. I mean, it's – I think you described though the objective very well, David, which is, you know we are matching basically our operating cash flow. We want that to cover our capital program as well as our dividend. And so, we've calibrated that on a average WTI for the year of $55 oil, and so that's the modeling that we're doing today..

Kind of no answer. Thanks, guys. What if I (43:02) shot at 2018..

Yeah..

All right..

Okay. Thanks, David..

And our next question comes from Matt Portillo with TPH. You may begin..

Good morning, guys. Just a quick follow-up to David's question maybe looking at it at a different way. Looking through your previous presentations, you guys talked about $4 million well costs in the Eagle Ford and about a $6 million well cost in the Bakken.

And so, looking at your net well count and then kind of the total capital budgets in both the Eagle Ford and Bakken, just trying to understand the delta in the net CapEx you're laying out, about $600 million in each play versus what the implied kind of well build-up would be from a bottom-up perspective..

Yeah. We haven't. And, again, we haven't really provided the phasing of that over time. But, you know, in somewhere like the Eagle Ford, where we are already at a somewhat steady maintenance level, you should expect wells to sales to be somewhat ratable through the quarters. And the areas where we're on a much deeper ramp-up, that's going to vary.

For instance, in the fourth quarter in Oklahoma, we only had eight wells in total to sale. So, with early on pad drilling and lower rig capacity in places like Oklahoma, at least in the early days of the year, it's going to be a little bit lumpy and bumpy in terms of when those wells to sales come to fruition..

Okay. Great.

And then just a question around kind of the inventory side of the equation, it's been a while since we've seen a inventory update in both the Bakken and Eagle Ford, and I was just curious if you can provide us some context, I guess, as we look at the run rate of about 100 wells or so in the Eagle Ford today and about 60 wells or so in the Bakken in the core, how you guys kind of think about the core inventory depth you have in terms of years.

Just trying to get a better sense of how we should think about that inventory as we progress over the next five, six years..

Sure, Matt. This is Mitch. Maybe I'll start with the Bakken. And, we're allocating two-thirds of our CapEx up there this year to the Myrmidon area. With that kind of activity level, certainly see several years of inventory.

Just in Myrmidon, we talked as well we're looking to extend our high intensity completion designs down to the Hector, but we've got about twice the position. And, certainly, with success there, we would extend that another several years as well.

To your Eagle Ford question, more than sufficient inventory to drive the long-term growth CAGRs that we talked about earlier on the call and in our release. And, certainly, the Eagle Ford, as Lee mentioned earlier, is going to play a role in that growth. So not uncomfortable with the inventory in either of those basins.

We've been working hard on finalizing our 2017 activity plans and making sure we're prepared to execute on the ramp-up. So still working resource updates across the company, across all three basins, and we'll try to share that with you all in due course..

Great. Thank you very much..

And our next question comes from Jeff Campbell with Tuohy Rose. You may begin..

Good morning..

Good morning, Jeff..

There was mention of secondary zone tests in the Midcon. I was wondering if you'd add some color on what zones you might be looking at in the STACK and the SCOOP, specifically.

And, also, will any of these tests be operated or are they all passive?.

Hey, Jeff, this is Mitch, again..

Hi..

Not really ready to provide a lot of color on specific targets. I guess, I would point you to our slide in the deck with the strack (47:17) column. And, we've kind of highlighted ones. You could probably pick those from activity in the area. They will – we are referencing primarily company-operated tests there.

So, those will be tests that we'll be executing on. And, obviously, as we get a little further into that, we'll share details as appropriate..

But, I think....

Well, maybe if I could just ask as a quick follow-up to that is, just will this be fairly even testing across your acreage or are you concentrating a little bit more on the STACK versus the SCOOP or vice-versa?.

Yeah. That's fair. I would say the concentration will be more weighted in the STACK..

Okay. Thank you. My other question was with regard to the Eagle Ford. And, you mentioned that there was going to be increased lateral lengths.

I was just wondering if you have an average lateral length target for 2017, and also if you have a corresponding EUR estimate for that length?.

No. We're looking at a little bit longer lateral lengths there. As you're I'm sure familiar, the lease boundaries in Texas aren't as consistent as they are in areas like Oklahoma. So, we have some unique shapes. And the program is weighted towards some more 7,000-foot laterals in 2017 than we were in 2016.

We talked about, in the release as well, you know, we've brought 52 wells to sales last quarter. In aggregate 30-day IPs are right on the type curve, and top 10 wells kind of range from 1,400 boe per day to 2,100 boe per day, but nothing really further to share on that at this point..

Okay. So, it sounds like that, even though the length is going to be 7,000 or whatever, it's not radically different than what you've been doing. And we can pretty much assume the type curves that we've – that have taken us up to this point for 2017.

Is that fair?.

Yeah. I think, I think the way I would maybe characterize it, Jeff, is that on average our lateral length is up a bit for the reasons that Mitch just described, but it's incrementally up from the average where we've been in the past..

Okay. That's very helpful. Thank you..

And there are no..

Well....

That concludes our.

Go ahead. I'm sorry..

That concludes our question-and-answer session. I would like to turn the call over to Lee Tillman for closing remarks..

All right, thank you very much. Well, I want to thank everybody for their questions and time today and your interest certainly in Marathon Oil.

We believe our strategy of focusing the business on profitably growing production from our high quality inventory in three of the best oil basins in the world, maintaining a strong balance sheet with a competitive cost structure, coupled with competitive long-term oil growth rates that are achievable within cash flows at strip pricing, positions us very favorably to outperform the competition in 2017 and beyond.

And with that, I will close the call and just say thank you to everyone..

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