Christopher C. Phillips - Director-Investor Relations Lee M. Tillman - President, Chief Executive Officer & Director John R. Sult - Executive Vice President and Chief Financial Officer Lance W.

Robertson - Vice President-North America Production Operations Thomas Mitchell Little - Vice President—International and Offshore Exploration and Production Operations.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Evan Calio - Morgan Stanley & Co. LLC Doug Leggate - Bank of America Merrill Lynch Ryan Todd - Deutsche Bank Securities, Inc. Brian A. Singer - Goldman Sachs & Co. David Martin Heikkinen - Heikkinen Energy Advisors John P.

Herrlin - SG Americas Securities LLC Scott Hanold - RBC Capital Markets LLC Guy Allen Baber - Simmons & Company International Phil J. Jungwirth - BMO Capital Markets (United States) Pavel S. Molchanov - Raymond James & Associates, Inc. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc..

Good morning. And welcome to the Marathon Oil Corporation's Second Quarter 2015 Earnings Call. I'm Chris Phillips, Director of Investor Relations. Also on the call this morning are Lee Tillman, CEO and President; J.R.

Sult, Executive Vice President and CFO; Mitch Little, Vice President International and Offshore Exploration and Production Operations; Lance Robertson, Vice President North America Production Operations; and Zach Dailey, Director of Investor Relations.

As has become our custom, we released prepared remarks last night in conjunction with the earnings release. You can find those remarks and the associated slides at marathonoil.com.

As a reminder, today's call is being recorded, and our comments and answers to questions will contain forward-looking information subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

I refer you back to the aforementioned slides where you can find our full Safe Harbor statement. With that, I will turn the call over to Lee..

activity in CapEx reductions, capital efficiency and productivity gains, operating and G&A cost reductions and non-core asset divestments.

We have successfully and efficiently achieved our planned activity reductions in the three resource plays to yield a program that will hold production volumes for the balance of 2015 while still progressing our strategic objectives in all three plays.

Those objectives are co-development in the Eagle Ford, integration of completion and downspacing pilots in the Bakken, and protecting our valuable leasehold in both our SCOOP and STACK positions while investing in high return outside operated opportunities.

Even with these planned reductions, we will still deliver on our growth targets of 5% to 7% for the overall company and 20% for the resource plays year-over-year. We've also raised the low end of our total company E&P full-year production guidance, essentially increasing the midpoint despite the announced asset sale.

Our planned deceleration in capital spend is evident in the sequential reduction in our capital program by almost $500 million and the significant decrease in wells to sales relative to the first quarter.

We had already cut exploration spend by half from last year and are continuing to moderate forward commitments as we reset our strategy, including withdrawal from new country entries that do not compete for capital allocation. For capital efficiency, we've captured greater than $300 million in D&C savings in the U.S.

resource plays, or about 20%, and are driving for more. Our completed well costs continue to fall and our well productivity continues to improve.

We have reduced unit operating cost in both of our E&P segments from the year ago quarter, more than 30% in North America and 25% in International ex-Libya, and have reflected this in our forward full-year guidance for unit cost, lowering them $1.25 and $1 per BOE respectively.

We were quick to address G&A cost in the first quarter as we finalized our activity plans and implemented a workforce reduction of about 400 people that is expected to generate annualized net savings of approximately $100 million.

Our non-core asset sales are progressing with signed agreements for approximately $100 million toward our target of over $500 million. This recent transaction confirmed that the right assets will generate a competitive process and yield compelling deal metrics even in the current environment.

All of these actions combine to give us confidence and driving toward cash flow neutrality in 2016, inclusive of non-core asset sales. We are only just beginning the budget process for 2016, but we'll focus capital allocation to the high-return U.S.

resource plays as several longer cycle investments run their course by the end of this year and exploration spend continues to decline. Our forward look positions us well below our 2015 $3.3 billion capital program.

And while our 2015 quarterly exit rate will be in the range of $700 million to $750 million, we still have the ability to flex down or up as required. Additionally, we expect expense reductions and capital efficiency to continue into 2016.

We are optimizing our business around a lower cost structure, holding production levels and protecting our investment in our high-return U.S. resource plays while challenging all other spend in excess of that. Our U.S.

resource plays continue to deliver solid returns at current pricing, with capital efficiency and enhanced productivity lowering breakeven prices.

Our last disclosure on our five-year drilling inventory showed 70% of our inventory profitable at $50 a barrel WTI and that analysis did not incorporate our most recent completed well cost savings and productivity enhancements. We have multiple years of high quality inventory that can deliver competitive returns in the current environment.

We do not believe this is a time to be accelerating inventory and associated production from short cycle investments. We believe it's a time for discipline, continuous cost reduction, sustainable efficiency, maximizing returns and balance sheet protection. We continue to have a strong balance sheet with $5.5 billion in liquidity at quarter end.

As we move into the second half of 2015, we look forward to providing more results from our co-development in the Eagle Ford, operated downspacing activity in Oklahoma and resource updates for the U.S. unconventional plays.

I want to conclude by taking a moment to recognize our Marathon Oil employees who have been the driving force behind our results in this very dynamic environment. They have stepped forward to lead our efforts in cost reduction and efficiency gains, and have kept their focus on execution despite the distraction of the macro environment.

Our employees are committed to an enterprise-first view, for which I'm both thankful and proud. With that, I'll hand it back to Chris to begin the Q&A..

Thanks, Lee. Before we open the call to questions, we'd like to request that you ask no more than two questions with associated clarifications, and you can re-prompt as time permits. With that, Cynthia, we'll open the lines for questions..

Our first question comes from Ed Westlake. You may begin..

Yes. Good morning. And just wanted to touch base on completions in the Eagle Ford, obviously, the whole industry has been experimenting further with completion technology and seeing some incremental results.

Just wanted to get a sense of how you see completions, where you are in terms of testing, and what improvements that you've seen, particularly in the Eagle Ford?.

Ed, I would say, for the second quarter and actually the previous couple of quarters, the focus in the Eagle Ford has been to maintain the very high initial production and the high EURs we have. We have some of the highest of each of those in South Texas.

Even as we have taken, for example in the second quarter, and taken more than a third of the total wells are outside of the lower Eagle Ford, in either of the Austin Chalk or the Upper Eagle Ford.

We've really accelerated that co-development in multiple horizons – three, and in some cases, four horizons developed across our acreage position, particularly in Karnes County, to see how much vertical density in that total package we could create, as well as the 40-acre and in some cases, 30-acre spacing we have horizontally in that.

So, what we're really most excited about is that, even as we've materially increased the complexity of the co-development through the stack-and-frac pilots, what we've seen is that the production per well in the other horizons, specifically the Upper Eagle Ford and the Austin Chalk, have competed very favorably with the traditional Lower Eagle Ford.

So, we're still getting great results that are competitive, in returns among the best in our portfolio from all three of those horizons, which helps our long-term inventory and really helps our capital efficiency, as we can move to develop more wells per pad across the Eagle Ford..

So, yeah, that's clear and very helpful. So, there's an optimization and a science phase and then perhaps, as you go forward and you settle down, you go for more – once you've proved it, you go for more completion efficiency improvement.

Is that a logical thought process?.

We're always looking for more efficiency, Ed, into that, and we continue to get among the most stages per frac fleet in South Texas out of each of these fleets by very carefully planning our logistics, both on the water and the proppant side, and managing those.

I think in the release you saw, we indicated we're going to drill about 20 more wells this year within the same capital in Eagle Ford. We're really just going to use the balance of those wells to manage full frac fleets of activity to drive highest efficiency on the completion side, which is where we have the most cost exposure.

So we want to make sure that side is very well supplied with inventory, just so they stay at maximum efficiency..

Okay. Very clear. Thanks very much..

And our next question comes from Evan Calio. You may begin..

Hey, good morning, guys..

Good morning..

Good morning, Evan..

In your prepared comments, you talked about $2.8 billion to $3 billion annual CapEx run rate, 2015 exit. I know you mentioned that it's early, but clearly the market is focused on 2016.

Philosophically, how do you think about relative outspend into 2016 and kind of balancing the attractive returning assets in the current environment, your financial flexibility and the dividend? Any comments there on an outspend range, or how you're thinking about it approaching 2016?.

Yeah, maybe Evan, let me maybe talk a little bit about our CapEx views as we exit 2015 and look ahead to 2016, and then perhaps I'll let J.R. maybe talk a little bit on the cash flow outspend question.

But you know, as we kind of think about the current prices and look ahead to 2016, we would envision certainly a material lower budget than where we are, below that $3.3 billion and certainly, as you mention, our run rates coming out of this year are certainly south of $3 billion.

We're honestly, though, Evan, right at the beginning of our budget process for 2016, and clearly any actions that we take, our capital allocation is going to be governed in large part by what we see in the commodity price environment.

But in general, our strategic approach is going to be to prioritize our available capital to those highest return investments that we have in the North America resource plays. And the balance will go to any previously committed kind of non-discretionary longer cycle requirements.

I would also expect, in 2016, that our exploration CapEx is further reduced. It was cut in half this year. And as you think about, even for a flat to reduced budget into 2016, the North America component of that will still grow in that context, because we have some long cycle investments running their course in 2015.

We have further reductions, as I mentioned, in exploration spend, and we also have some non-recurring U.S. infrastructure investments this year in 2015 that are going to provide some accommodation space, if you will, for additional North America investments. Again, our goal is going to be to target as much investment as we can to the U.S.

resource plays, based on the prevailing commodity environment and available cash flows. We still have the inventory to deliver strong and long-term growth, and we're going to protect that optionality as we move into 2016. With that, maybe I'll just offer it over to J.R., just to talk a little bit about cash flows..

Yeah, Evan, this is J.R., and I think Lee really kind of, I think, summarized it really well. I mean, it is early in the process but philosophically, from my standpoint, he referred to, the balance sheet strength's going to remain a priority.

Again, philosophically, I want to see 2016 be as close to free cash flow neutral, including asset sales, as we possibly can.

Many variables to that equation; capital, clearly, capital activity, capital efficiency, capital spend, operating cost efficiency, and of course our success on the ongoing asset sales programs, are all variables in dialing up and down that respective capital profile.

But I think your takeaway should be that we continue to have a great deal of flexibility to manage that and to really achieve all of what we want to achieve, in terms of protecting that balance sheet, in terms of – if the commodity price environment is supportive of it, to continue to put those North American unconventionals back on a growth track going forward.

The one point you did bring up that I'll go ahead and answer, you brought up the question with regard to the dividend. And as you might imagine, in this environment, it's a question we frequently get. Evan, it's still a very important element to when you think about the total shareholder return for our shareholders, even more so in this environment.

And it does, it continues to be that first call on capital in our capital allocation process. The board is very thoughtful and very considered when they address this issue each and every quarter. They are making sure that it's still meeting our long-term capital allocation objectives and they'll continue to fulfil that roll each and every quarter.

But honestly, sitting here today, I feel very good. Good solid balance sheet, $5.5 billion of liquidity, $2.5 billion of that in cash and cash equivalents and I think we've got a tremendous amount of flexibility to still continue to deliver that important element to our shareholders..

Great. That's it. That's helpful. Let me ask a second question or a segue in kind of an area which I presume would continue to get an increased allocation of capital in Oklahoma.

You've added small working interest across a larger number of wells into the second half of the year versus prior spending plans in what appears to be very attractive neighborhood.

Could you discuss how far away you think you are from putting Oklahoma, particularly STACK, into full development mode? And could you talk about, I guess, that shift in going to non-op and whether that's planning to leverage a fuller dataset in helping you to and/or lease or subsequently develop that resource?.

Yeah. Evan, let me maybe start on that one as well. I think we – we're still in the very early days in the development in Oklahoma in both the STACK and the SCOOP but, as we've said in the past, we certainly believe with well over 1 billion barrels of 2P resource that this is a tremendously important growth engine for the company going forward.

Because, again, of capital constraints in the current environment, we're running a two rig operated program there. That's designed to ensure that we protect our very valuable leasehold in both the SCOOP and the STACK.

And as you mentioned, what we're doing is we're participating at a lower interest in the non-operated part of our portfolio to really leverage our funds to continue to grow our data set in Oklahoma in a very cost effective manner. In fact, in total, we've redeployed about $60 million into the Oklahoma non-operated business.

And of course, we gain the information and the data from that investment in addition to the barrels, which allows us to continue to move toward that vision of what a full field development will look like ultimately in the SCOOP and the STACK. But I'd just emphasize that we are early days, but we're making good progress.

Already you've seen some movement in our completed well cost downward in Oklahoma, reflecting some good efficiency as well as commercial work by the teams.

And I think as we move to scale, we move out of leasehold mode, we get into pad drilling, those efficiencies are simply going to increase over time and we could see even more reduction in the those costs..

Any update on what you added in the quarter lease-wise?.

This will be the last question, Evan..

Yeah, sorry. Any update on leasing activity in the quarter in Oklahoma in particular? I'll leave it at that..

No real update there that's material..

Great. Thank you..

Thank you..

And our next question comes from Doug Leggate. You may begin..

Thanks. Good morning, Lee. Good morning, J.R., and good morning, Chris..

Morning..

I guess I'm trying to think of how to word this question so it doesn't count as two.

On the dividend, Lee, I understand you've been very clear in the past about your commitment to why you think the dividend is important, but when you talk about cash breakeven, does that include covering the dividend? And I guess what I'm really kind of trying to get at is when you look at who your peer group is nowadays, folks who generally don't have that dividend commitment or obligation, they are able to redeploy – let's assume now it's $600 million or $570 million in your case towards accelerating something like the STACK or the SCOOP.

Why is it better value for shareholders to see that dividend payout in this environment as opposed to moving it towards those high-graded assets? And if you could clarify the breakeven comment, please? And I do have a follow-up. Thank you..

Yeah. Absolutely, Doug. No worries. Just on the cash breakeven that J.R. was addressing in his earlier comments, we view that as inclusive of the dividend. When we think about cash flow neutrality, we're certainly wanting to cover all of our obligations from a capital allocation standpoint and the dividend is an important one of those.

Obviously, with our dividend yield where it sits today, that's a bit different looking than it was in a different commodity price environment, but we still feel that this is an important way to deliver value to our shareholder.

And we tend to look at the dividend in the context of our overall capital allocation and in conjunction with the growth that we can generate organically within our very strong North America resource play. So we view those two things as needing to be viewed collectively.

From an investment standpoint, I think in this lower price environment, although you're correct in that it perhaps puts a bit more pressure than some of our peers, I do believe that is a key element of the return that we offer in this type of environment. And as J.R. very well put it, we're sitting with $5.5 billion in liquidity.

We do not feel that we need to make any alteration in the way the dividend competes for capital allocation today..

I appreciate the clarification.

Just to be clear on the yield comment, do you feel that the yield – you're not indicating any intent to cut the dividend, are you, with that yield comment?.

No..

My follow-up is really a similar kind of question this time on exploration, because clearly you're building up your onshore resource backlog which by definition is lower risk.

I'm wondering if you could touch on the bigger than expected exploration charge in the current quarter and how you see exploration as a strategy fitting into a lower for longer oil price environment and I'll leave it there? Thank you..

Yeah, let me maybe take the high-level question first, Doug, which is more around exploration strategy, how does that fit into our portfolio.

As we've shared previously, Doug, we've been assessing our conventional exploration strategy and in really in the context of its ability to compete for capital allocation within the current portfolio which does include, as you well stated, the North America inventory.

And it must compete really on a risk adjusted return basis and we really started this assessment some time ago. It really wasn't prompted by the current macro environment. It was really prompted by the depth and quality of the inventory that we saw in the North America resource play. So we were a bit ahead of the curve.

We've already taken the step to reduce exploration essentially by half in 2015. And we certainly see a path that will allow us to moderate that further into 2016.

I also mentioned in my opening comments that we most recently withdrew from some new country entries that we just simply felt in the current environment did not compete for capital allocation.

So, when you consider the current commodity price environment, when you consider the depth of our resource inventory in North America and the limited capital to invest, it's just simply getting tougher and tougher for conventional exploration to compete for capital on a risk-adjusted basis.

Back to your specific question on kind of the uptick in exploration expense, we did have a write-down in Birchwood, which is our in-situ property in Canada, which contributed to that, Doug..

Very clear. Thanks a lot, guys. Appreciate the answers..

Thank you, Doug..

And our next question comes from Ryan Todd. You may begin..

Great. Thanks, gentlemen. If I could and maybe with my first question follow up a little bit on CapEx. You show in your presentation effectively a flatlining of production in the second half of 2015.

Is it reasonable – I know you can't give 2016 outlook, but is it reasonable to think of that level of that $700 million to $750 million CapEx level as kind of a reasonable idea of maintenance CapEx and its ability to hold the production flat for longer? And you also mentioned the roll off of long cycle spend, expiration reduction potential and non-recurring infrastructure spend.

Could you maybe put some numbers around those that we could get maybe a bit of a better pro forma estimate for what the run rate on CapEx looks like into 2016?.

Yeah. Well, yeah, let me maybe start with addressing what I think is more a question around maintenance capital, and I think first and foremost, Ryan, of course the $700 million, $750 million run rate includes the full portfolio. When we talk about maintenance capital, we tend to focus in on the resource plays themselves in aggregate.

And our best estimate of CapEx required to hold those resource plays flat is around $2 billion to $2.1 billion. Of course as capital efficiencies and productivity improvements kick in, there'll be actually downward pressure on that maintenance capital.

And so, when you think about looking ahead and how long could maintenance levels be sustained, my answer to that really would be that we have multiple years of high quality, high return resource play inventory that could ostensibly drive a maintenance level program even in a $50 barrel WTI environment.

Again you'll recall, as I mentioned in my opening comments, that when we took a look in our most recent disclosure on our five-year drilling inventory, over 70% of our wells were profitable at $50 barrel for WTI.

So you're right, we have had this rapid deceleration from first quarter to second quarter in our overall capital program, that $500 million that I quoted. We've now kind of settled into, I'd say, a maintenance capital mode in the resource plays.

But bear in mind, riding on top of that are some of our other investments that will be a little bit more lumpy and bumpy, including – we may even see a little bit of an up in third quarter because of some non-recurring infrastructure investments and a few other non-recurring items in our International portfolio.

But as you look through that lumpiness in the second half of the year, that $700 million, $750 million exit rate feels about right, with some plus or minus there.

Your other question was around, how much of some of these longer cycle investments may run their course in 2015? And the items there that we talk about when we mention those items are things, like the work that we're doing currently on the EG compression project, which is now heavily in fabrication mode.

The work that we did in the EG drilling program, the work that we did also in the UK drilling program. Those are the types of items that we talk about.

And so, when we look kind on a net-net basis, as those kind of come off in 2016, there will be some puts and takes, but you're probably in the couple hundred million kind of dollar range, in terms of the accommodation space that that might create within the budget..

Thanks. That's very helpful. And maybe, if I could ask a follow-up and if we switch over to maybe the resource in the Bakken, you've got some results out there of 180-day update in high intensity completions, some pilot test results.

Can you talk a little bit about maybe your thoughts on the results of the tests, on the pilot test for spacing, and the implications for spacing going forward, and whether the high intensity completion, whether 180 days is long enough to maybe start to impact the type curve, or whether you're still waiting to see an eventual EUR impact?.

Sure, Ryan. I think in general, I'd say we're really, really pleased with the progress, broadly, from the Bakken completion pilots. You step back and look at what we have accomplished over the last several quarters, that material improvement in initial production.

Now, with the cumulative production of a group of wells reaching 180 days, you start to see that improvement hold up over time. We've consistently taken those new designs and applications and spread it across our entire portfolio.

I would add that, even as we've demonstrated these results that are kind of rearview mirror looking, we're continuing to progress even more intensive stimulations. I think we noted in the notes that, this group you're looking at has 40% more profit and about 10% more completion stages.

We continue to see opportunity even beyond that, for more intensity to drive those results further. I think, based on the results you're seeing and referencing, there's certainly some pressure on us to look at overall EURs and talk about those, perhaps later this year provide some more color and context on that.

And obviously, with more EUR combined with the Bakken well cost trending down to plus or minus $6 million, a material reduction there, I think you can see the value implication of the portfolio in Bakken from that. So again, we're very pleased with it, and by all means, we expect that momentum to continue..

And maybe if I could just add, too. On our last update on completed well kind of performance, our single well economics, we had reflected some of the early IP results that we were seeing from the Bakken completion trials, but we as of yet have not introduced the full EUR benefits that potentially we could garner from those wells.

So, that's still yet to come..

Great. Thank you..

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

Thank you. Good morning..

Good morning, Brian..

Wanted to follow up on a couple of the items surrounding free cash flow, and then capital allocation priorities.

You mentioned earlier the potential for free cash neutrality after asset sales, wanted to just check whether that was before dividend or after dividend? And then, if that dividends is priority number one, just how you're thinking about the secondary priorities of growing production versus letting it decline, allowing leverage to increase or – and I think I know the answer to this last one – issuing equity?.

Yeah, hey, Brian, this is J.R. I mean those are all the variables that we're trying to balance to achieve the optimal outcome of what we're trying to reach. In response to the question, my comments with regard to trying to target as close to free cash flow neutrality as possible is with dividends.

I mean, at the end of the day, I think that's vitally important, that we manage the business to where we're not overextending the balance sheet. That balance sheet strength's going to remain important.

But as you and I have talked about before, I think, Brian, during this low commodity price environment, I'm definitely leaning on it, and I want to lean on the balance sheet during this period. I just want to make sure I don't stress it too much.

So when I look forward into just an early forward view of 2016, it will be in terms of – the leaning on that balance sheet will be, I'd say, impacted by the timing of, ultimately, our asset sales programs.

There will be periods in which we're leaning on it more than not but that, at the end of the day, I want to try and ensure that, when we get through the year in 2016, that we still have a good solid balance sheet when we get to the end of the year..

Great. Thanks. And so it would seem like then, from an asset sale perspective, the ideal opportunity would be something that doesn't take a ton away from your cash flow generation but where there's some value.

Kurdistan comes to mind as potentially one of those opportunities, and perhaps you could give us an update on how you're thinking about what to do there? And then, if there are other opportunities out there you see in the portfolio, that maybe there's room for a targeted asset sale that wouldn't take away from the cash flow profile?.

No. I'll take a crack at the asset sale comment, and if you wanted to hear a little bit more about just specifically what's going on in Kurdistan, Mitch can answer that. But we've not been real explicit, Brian, with regard to where in the portfolio.

We've highlighted that they would be non-core, they would be assets that just, candidly, are not competing for capital in the portfolio. I think the one transaction we announced this quarter was a non-core natural gas, candidly a high cost asset as well, that was sold for, we think, very compelling economics for $100 million.

Just kind of step one in our target of achieving greater than $500 million of asset sales. So I think you should think that we're looking across not only the operating portfolio for non-core assets but also the exploration portfolio as well..

Thanks.

And if there is a Kurdistan, how Kurdistan fits in, I'll take that as part of the follow-up?.

Yeah. Brian, this is Mitch Little. I think just in terms of thinking about where Kurdistan fits, we've got three blocks there, as I'm sure you know, at different levels of maturity. The operated block at Harir, we've completed testing of our appraisal well, the well results were largely in line with pre-drill expectations.

And so, at this point, we've demobilized the rig. We've substantially completed all of our work commitments there and we're integrating that data into the rest of the technical database and commercial assessment headed towards a commerciality decision on that block later this year.

You're probably also familiar the Atrush Block Phase 1 development is progressing towards a 30,000 barrel a day gross facility, should come online in 2016. And then our interest in the Sarsang Block is progressing towards approval of the field development plan, which will be a phased development ramp-up over time..

Yeah, Brian, I'm sorry, I should have stepped in or answered that before Mitch. But the reality is, I think we have generated an asset through the work that Mitch and the team have done that has had very solid subsurface success.

I think the question we have to continue to ask ourselves is as we think about future investments in Kurdistan, whether or not they compete for capital with the rest of the portfolio.

And if the answer to that is, no, we want to ensure that we can actually capture the value that's been generated by the team in order to redeploy that capital someplace else.

So, as I said, I'm trying not to be explicit with regard to what particular asset so I don't put myself in a competitive disadvantage in a process, but you should expect that we're looking across the entire portfolio for candidates..

And our next question comes from David Heikkinen. You may begin..

Every call..

You're a good sport, David..

I am. I need to figure out a way to respell my name or something so they pronounce it correctly.

As I think about the profitable at $50 oil, are you using a well level economic or is that asset level inclusive of all costs or how do you define that inventory and metrics for profitable at $50 oil?.

Yeah. We tend to look at single well economics from an external standpoint, which allows us to benchmark, I think, more effectively with what others put out into the public domain, David.

I think internally, though, we also want to look and see from a fully burdened level what is the return not only down to the well level, but at a program or even a rig line in a particularly area in a particularly play. We want to make sure that we fully understand the fully burdened economics of those wells.

So, there is an aspect of it, which is we want to be able to make sure that we can compare externally, but certainly internally we want to make absolutely sure we understand the total return from those investments..

Yeah. Just to be clear, what Lee's point is is that when you look at our completed well costs, that truly is just completed well costs.

But when you look at the returns that we share, those have been burdened by facilities at least individual well facilities necessary for flow, not to the extent of broad central facilities but individual well facilities..

Yeah.

So it has all the surface, everything needed?.

Correct. Artificial lift, et cetera..

Yeah. Basically the lifecycle cost of the well ex any main centralized facilities, David..

Is there any particular area where the other 30% falls? I mean is it Williston, STACK, Eagle Ford in that order? That's probably I would do, but....

Yeah. The last disclosure that we offered up when we kind of showed the relative economics of various plays from a single well economics standpoint, it was clear that Eagle Ford and Oklahoma were at the most competitive portion of that plot.

The higher quality in the Bakken was also in that same zip code and that really is what drove our capital allocation as we came into to 2015.

I think what you've heard is that the Eagle Ford as well as Oklahoma have continued to also improve from a single well economic standpoint, from a cost and productivity standpoint, but also the Bakken has continued to improve its competitiveness as well.

And we'll hopefully be able to share a little bit more color on that a bit later in the year, as we're able to roll in some of the specific updates on EURs and single well economics.

But I think that that order in terms of capital allocation is exactly what you see in our current portfolio, which is the Eagle Ford wells, particularly condensate and high-GOR oil to certain extent are still very strong from a return standpoint. Both the SCOOP and the STACK still compete very favorably as well.

And then in the higher quality areas of Bakken such as the Myrmidon, they're also competing for capital allocation..

And then asset sales around $500 million next year, as well is a reasonable assumption?.

David, I just think what you ought to assume is what we've talked about is greater than $500 million, haven't been really explicit on timing. I thought give it 12 months from when we announced it again, but we wouldn't have put a target out there if we didn't have some degree of confidence.

But you should expect that program to continue and not necessarily stop if we cross the $500 million level..

Yeah. Okay. Thanks..

Thanks, David..

Thanks, David..

And our next question comes from John Herrlin. You may begin..

Yeah. Hi..

Hey, John..

Some quick ones. When you look at your portfolio, Lee, I want to get back to the short cycle, long cycle type activity.

What do you think's kind of an ideal balance and if you have more of an emphasis on short cycle, is it time to revisit hedging?.

Yeah. Let me, I'll may be let J.R. jump in on the hedging question. But let me first talk about long cycle versus short cycle. Right now, the bulk of our investment dollars are flowing into North America short cycles and the driver there is they have the highest risk-adjusted returns in the portfolio that we have today.

So, for us, it's probably a little bit less about short cycle, long cycle than it is about where can we generate the highest risk-adjusted return.

And to the extent that we continue to see long cycle or longer cycle opportunities and great examples are the things that we've done in Equatorial Guinea and the UK this year in terms of the program drilling that we've done there that are very strong from a capital allocation standpoint and have added very profitable barrels to the portfolio.

So, in no way are we necessarily turning our back on longer cycle type investments, but the balance is going to be dictated by the opportunity set we have in the portfolio and being driven by generating those highest risk-adjusted returns.

From a hedging standpoint, certainly we view that as just an element of overall commodity risk management, and maybe I'll let J.R. comment on that..

Hi, John. You and I have talked before. It's definitely a tool that we need to be using, we are using. We've been far more active than, I think Marathon has been in the past.

Would I like to have more hedges on today, yes, but we have probably at least for the balance of 2015 and I know the market is more concerned about 2016, we've probably got about 35,000 barrels a day hedged for the balance of 2015 and we really just were able to begin to establish a position in 2016 before the market kind of fell on us.

But it is definitely going to be a tool we're going to continue to use..

Great. Thanks, J.R. One other one for me. In the Eagle Ford, you had incredible drilling efficiency.

Are you changing crews, are you getting different rigs, how can you have this level of improvement in your well design or execution?.

John, I think what you're seeing is just a recognition by a team who refuses to accept that they've done their best work already. They continue to see in the future, they can be innovative and thoughtful.

In this case, part of the change is that as we've moderated activity, we've certainly kept the best rigs and the best crews, because it helps both our operational efficiency as well as our environmental safety performance.

We've retained rigs with the highest specifications, so the right types of capabilities that we moved to in that rig fleet that can really drive it. And those unique attributes of those rigs allow us to use other types of downhole tools. The combination of those technologies together has really delivered this performance.

And I would say while 1,800 feet per day was materially better than the year ago quarter, our best rigs are at 2,600 feet, 2,700 feet per day already, which shows you the gap, right. If we can get the whole fleet to there, there's still room to improve that overall. We see that as sustainable.

And in fact, as we've moved to the stack-and-frac pilots and the co-development of multiple horizons, we actually think that enables that type of efficiency further, because when we're going to drill more wells on each pad as we go to development..

I think, John, too, it's probably important to note that when we look at the true pace at our drilling performance in the Eagle Ford, where we had one of our best rigs deliver 3,100 feet per day. It just gives you a feel for just how much more room we have to drive toward if we're averaging 1,800 feet for the quarter.

So it does show that there is continuing efficiency gains that can be made. Now will we get that immediately across the whole fleet? No, but it does set that marker out there of what can be achieved with the best crews, the best equipment being brought to bear..

Great. Thanks, Lee..

Thank you, John..

Thanks, John..

And our next question comes from Scott Hanold. You may begin..

Thanks. Good morning..

Good morning, Scott..

Hi, Scott..

Hey.

If I could step back and again kind of focus on big picture, where Marathon's going at this point in time, be somewhat agnostic to current low commodity prices, with the resource potential that you all are building in some of the North American resource plays, is there a transformation occurring where Marathon is going to become more focused on these lower risk, potentially higher returning short cycle opportunities? And again, being somewhat agnostic to low prices right now?.

Yeah. Absolutely, Scott, I mean that transformation is underway – has been underway. I think as we have made this very decided pivot to North America resource plays for clear economic reasons, you're seeing that in where our investment dollars are flowing.

And you're right, we have this incredible 3 billion barrels of 2P resource inventory in the three core U.S. resource plays that affords us a tremendous amount of future opportunity. And our challenge is ensuring that we get the appropriate investment levels driven to those three core plays and bring those up to scale development.

I mean, we're really at scale in the Eagle Ford. Certainly, we've been in Bakken at scale for some time as well, but Oklahoma is still an area where we would like to see more capital invested and not just the non-operated but also the operated program.

And certainly as we think about that incremental amount of capital coming available to invest, we absolutely see that flowing to places like the Eagle Ford and Oklahoma..

Okay, good. Thanks.

And as a follow-up and I know both of you all have been in this industry for quite some time and, J.R., you're obviously experienced from some of your past firms, with the low price environment we are in right now, can you discuss from an industry consolidation perspective, your view on what could occur, and how Marathon fits into that?.

Yeah, well, it's always tough to speculate, I think, on the M&A space. I think right now, with the dynamics that we're seeing in the marketplace, it's very challenging, I think, to see a lot of deal activity. And in fact, that's really what's played out.

There's been a few one-off opportunities that were probably taken, the decisions may have been taken in a slightly different environment than we find ourselves today.

But with equities very depressed, I think with everyone kind of reacting to another dramatic downtick in pricing, it's hard to imagine there's going to be a lot of that type of activity, at least in the near-term.

Now, as you look further ahead, and we see a more persistent kind of lower for longer price environment, then I think the concept that there will be additional consolidation, additional opportunities come available to those that are prepared to take advantage of those, then absolutely I would agree with that..

That's great. Thank you..

And our next question comes from Guy Baber. You may begin..

Good morning, everybody..

Hi, Guy..

Good morning, Guy..

You fared a little bit better than David did on the last name..

That's right. I have been called Gee numerous times, so Guy is better, I'll take it. I was hoping to clarify a few comments you just made earlier in the Q&A, Lee, but you mentioned that in this price environment, capital spending would be down from the current year.

You also said that even with a flat to lower budget in 2016, that the North American production component would grow. So could you just elaborate on that comment a bit? Want to make sure that we have that right.

And really just trying to understand that assertion, and square that with our understanding that the unconventional production would exit this year below the full-year average, and then on maintenance CapEx levels, you could hold that 4Q exit rate flat through 2016.

So just want to make sure we understand that trajectory and some of the moving parts that we might be missing?.

Yeah. No. Absolutely. I tried to address, again honestly, we're not – we're very early in the planning cycle for 2016, but just thinking about it conceptually, we know that our capital budget will be less than where we stand in 2015.

In fact, the run rate that you mentioned as we exit 2015, that $2.9-ish billion (51:00) kind of run rate, certainly less than the $3 billion, that really does entail an ability to direct more capital deployment to the North America resource plays.

So, for a bit smaller pie, we're able to today dedicate a much larger slice to the North America resource plays, even in that scenario. And so, the ability to have that optionality to move from more of a maintenance capital mode in the resource plays to more of a growth mode, we still have that optionality within a reduced budget in 2016..

Okay. Great. Thanks..

Did that get it clarified, Guy?.

Yeah. That helps a ton. Thanks. That was the only one that I had..

All right. Thank you, Guy..

And our next question comes from Phillip Jungwirth. You may begin..

Yeah. Good morning..

Morning, Phillip..

On the Eagle Ford, you noted the 40% sequential decline in activity as the reason for lower production. Looking at the expected wells to sales in the second half, it looks like the quarterly average is going to be a little bit lower than what you had in 2Q.

So is the current activity run rate below maintenance CapEx for this asset, or can volumes still be held flat on better well productivity in the second half or a shallower decline, given that you probably had a lot of flush production coming into the year?.

Yeah, Phillip, I think you're seeing that actually very well. Compared to the previous several quarters, where we've had in excess of 90 wells to sales, in the second quarter, we had 52 wells per sales, which is driving that production in Eagle Ford downward.

Really, the wave of those higher productivity wells that are very early in their life coming down has kind of overwhelmed the number of new wells to sales. I think from a perspective of activity across North America, including Eagle Ford, has come down about 45% for us, what you really see is, we're managing that downward to a point of stability.

We will have roughly the same number of wells, plus or minus, in the third quarter and fourth quarter in Eagle Ford specifically. In any given quarter, our working interest moves around a little bit within that, so the number of gross wells and net wells can move a bit.

So I think in general, we are guiding toward relatively flat production quarter-over-quarter, and we're managing that large activity downward in the quarter. I would say, too, some context on that is, even as we said the wells to sales were lower in Eagle Ford, I think it's important to note we went from five frac fleets to two frac fleets by April.

So we were down to that lowest level of wells to sales driven activity by very early in the second quarter, which kind of added to that deceleration impact..

Okay. Great. And then, can you discuss any results from the one Osage well brought on during the quarter? I think Marathon might be the first to drill a well in this zone.

Based on what you know to date, how would you also compare this emerging play to both the Meramec and the Woodford?.

Sure Phillip, last year we started an exploration program in STACK focused on Meramec and the Osage.

That Osage well was the last well of the initial group, our initial foray into the STACK in an operated basis, I think you may recall in the second half of last year, we actually increased activity in Oklahoma up to six rigs and that well was drilled, effectively starting right after Christmas and is sort of the last well in that program.

We've evaluated the results from all of those. We continue to see the Meramec is the most valuable zone in that area in general. I don't think we foresee more Osage activity anytime in the near term..

Great. Thanks..

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

Thanks for taking the question, guys. You're talking about selling some assets in an extremely depressed environment where there are plenty of distressed sellers that are in far worse shape than you are.

Isn't it kind of leaving money on the table if you're monetizing just about anything right now?.

Yeah. Well, first of all, I don't view our non-core assets as being distressed sales.

And the reason I say that, Pavel, is that when you think about the type of assets that we will put in the market, we believe that there's still a very strong competitive environment for those assets and I'll use the East Texas, North Louisiana Wilburton transaction as an example. We had a very strong response to the data room.

We had well over 20 proposals for the property. When you look at the deal metrics, they were very compelling on cash flow multiple basis, over 9X.

And so, we feel like for the right type of asset, there is still a ready market out there and I would not want to leave the impression that we're selling anything at reduced value or low value to our shareholders. I mean we don't view these as distressed assets, we simply view them as part of our ongoing portfolio management.

And if we can't capture fair value, then we'll continue to operate. In the case of the East Texas, North Louisiana Wilburton deal, it was a gassy asset, it was no longer competing for capital allocation, relatively high unit cash cost.

We had a strong competitive environment for it and the deal metrics were very competitive in this pricing environment or others. So I think we feel very good about our ability to continue to transact at fair values..

Understood. Just to clarify, it's not your assets I was calling distressed, it's plenty of others (57:08) in the market that are in that state. Now my follow-up is, you talk about flexing the balance sheet into 2016, debt-to-cap is currently at 29%.

How high would you be comfortable letting that metric go up?.

Yeah. What I would tell you is I've always tried to be careful to draw hard and fast rules.

But when I think of looking through 2016, when I take into consideration what I said before about the variables around capital, operating cost structure, asset sales programs, I still want to ultimately manage the balance sheet through 2016 to, let's call it, as close to 2.5 times net debt-to-EBITDA as I can in this low commodity price environment.

Now that's going to be lumpy. It's going to be dependent upon the timing of various asset sales and so that will become a bit higher than that. But that's ultimately one of the variables I'm trying to manage to.

And as commodity prices then begin to stabilize, whether that's early 2017 or you decide when, then ultimately you'll see that leverage get back to its more traditional levels of two times and below..

Okay. Useful. Appreciate it, guys..

Thank you..

Thanks, Pavel..

And our next question comes from Jeffrey Campbell. You may begin..

Wow, I didn't think you could mispronounce Campbell, but that's okay..

Good morning, Jeff..

My first question regards the Oklahoma resource plays, the increased non-op participation.

I was just wondering, are the choices driven by any specific operator performance or is it driven more by geography?.

Jeffrey, I think overall, we're focused on value. We have a substantial core acreage position in both the SCOOP and in the STACK. When we see activity in that core high-value acreage, where we've seen great historical results and from recent data we expect those results to be great in other areas.

We're choosing to participate in those wells to capture the data and leverage both the collection of that data and integration of it to drive toward full field development. And to some extent, if you didn't participate in those valuable acres, it's an opportunity lost. We certainly want to capture all those opportunities.

So it's not really driven by an operator, it's driven by our perceived value of the acreage and the opportunity. I'd say within the context of that, we see more – I'd say, more execution friendly operators than others. And as you'd imagine, based on that, we make economic decisions based on how we feel they can execute..

Okay. That's helpful. And my other question was on slide 17 regarding the Bakken spacing pilots to this point. The ranges appear less prolific on some of the non-spacing data that's provided, yet a large production uplift was identified out to 180 days.

So I'm wondering if you can help me to understand how to interpret the data that's being presented? And as well, if you could indicate how you feel the pilots are performing relative to your expectations at this point?.

Sure. So with three spacing pilots online, I feel like we've made a lot of progress at moving that forward on an operated basis. I'll kind of start and work south to north, if you will. Spacing pilots are in three different areas, starting in the south, it's Middle Bakken, so it's on a six well per Middle Bakken pattern overall.

There is a wide range of results here.

I think in the case of that pilot in the Ajax area, when you look at the aggregate, or all of the wells on there, you'll see some above type curve, you'll see some a little below but when you put them together, they look like they're performing very in line with our early expectations for that, despite being at closer spacing than stand-alone wells.

So that gives us a lot of encouragement. We expected some differentiation. In some cases, what we'll find is, when we go in and there's more than one parent well or older well in the area, you will see some depletion impact, and the new well that's near that older well will be impacted modestly by that.

But in aggregate, we tend to look at the entire unit, how many wells, how many total dollars invested, what's the total production coming out of that. And so, that Ajax pilot, for example, is performing very much in line with those expectations.

Moving further north to Hector and that pilot, again we see a diversity of results, but in aggregate they're performing very similarly to our expectations for the early production. Some of the wells in those groups are more mature than others. So, several of those are at 90 days or 120 days, and they're continuing to perform well.

So, we're very pleased with that result overall. In these pilots, some of the wells vintage-wise had more aggressive stimulations than others based on when they were drilled and completed. And then lastly in Myrmidon, we see a wide range there too.

I think in the case of that one pilot, we intentionally looked at that pilot and said there are four older parent wells between those two sections or units that were developed together. And so the wells near those – the new wells near the parent wells are showing a lesser production than the wells that are further outlying. And that's not unexpected.

In our case, we want to test that as we have parent wellbores we need to work around. But I think, in general, we're still very pleased with the overall production and continue to see that as a validation of our spacing assumptions moving forward..

That's fantastic color. If I could just add a little follow-up, because the question was long enough to begin with.

Just to clarify, do these spacing pilots have any cost advantages over a more typical production pad, or is this just purely about trying to capture the maximum resource?.

Jeffrey, any time we have the opportunity to pad develop groups of wells, we have a great opportunity on the drilling efficiency side to capture those cost savings. Similarly on the completion side, we can leave a frac fleet on one pad and complete multiple wells, on both of those fronts, we gain tremendous efficiency.

And then lastly, on the surface facility, the ability to share those surface facilities also creates a scale efficiency. So, we constantly seek and desire the opportunity for pad development because it really does positively influence our capital..

Okay. Thanks very much..

Thank you for the questions and interest in Marathon Oil. I'd like to thank everyone again for their participation this morning. Please contact Zach Dailey or myself if you have any follow-up questions. Operator, thank you. This concludes today's conference call. And you may now disconnect..