Christopher C. Phillips - Director-Investor Relations Lee M. Tillman - President, Chief Executive Officer & Director Lance W. Robertson - Vice President-North America Production Operations Thomas Mitchell Little - Vice President-International Production Operations John R. Sult - Executive Vice President and Chief Financial Officer.

Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Doug Leggate - Bank of America – Merrill Lynch Ryan Todd - Deutsche Bank Securities, Inc. Matthew Merrel Portillo - Tudor, Pickering, Holt & Co. Securities, Inc. Brian A. Singer - Goldman Sachs & Co. John P.

Herrlin - SG Americas Securities LLC David Martin Heikkinen - Heikkinen Energy Advisors Guy Allen Baber - Simmons & Company International Scott Hanold - RBC Capital Markets LLC Hiram Monroe Helm - Barrow, Hanley, Mewhinney & Strauss LLC Pavel S. Molchanov - Raymond James & Associates, Inc. Jason D. Gammel - Jefferies International Ltd. Jeffrey L.

Campbell - Tuohy Brothers Investment Research, Inc. Roger D. Read - Wells Fargo Securities LLC.

Welcome to the Marathon Oil Corporation 2015 Q1 Earnings Conference Call. My name is Vivian, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Mr. Chris Phillips.

You may begin, sir..

Good morning, and welcome to Marathon Oil Corporation's First 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'll 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..

costs; efficiencies; and execution, and discuss how our actions will enhance returns and have us well-positioned for the current environment as well as when commodity prices show a sustained improvement. Rigorous cost control across all areas of our business is at the forefront of what we do each and every day, and the first quarter was no exception.

We reduced our North America E&P production costs per oil equivalent barrel to $7.94, down 17% from fourth quarter 2014 and 28% below the year-ago quarter. Operating cost reduction is hard work, and our teams have taken on that challenge. There is no one magic bullet, but rather, there's a diverse range of drivers within these savings.

A few examples include more coordinated deployment of contract labor, focus on compressor utilization, aggregating water production into gathering systems and optimizing our chemical programs. These types of savings are durable in nature and resilient to the commodity cycle.

In parallel, we continue to work with our vendor base and supply-chain experts to take full advantage of our scale to drive commercial savings. On the service cost side, we increased our year-to-date captured U.S. unconventional D&C service costs by an additional $25 million, bringing that total to $250 million.

That represents a 17% reduction from our revised activity levels, and we fully expect to secure more savings as the year progresses. And finally, on G&A, we have taken the necessary steps to scale our organizational capacity to match our activity level.

And our first quarter workforce reductions are expected to generate annualized net savings of approximately $100 million. During the first quarter, we have also made significant progress enhancing our returns through efficiency gains.

Our high-specification rigs in the Eagle Ford are a prime example and delivered pacesetter spud-to-TD results of under seven days, drilling 2,800 feet per day, significantly above the quarterly average of about 1,600 feet per day.

In the Eagle Ford, our EUR uplift was 26% for condensate wells and 79% for high-GOR oil wells, relative to fall of last year, while completed well costs have fallen about 15%.

Finally, we are reallocating more than $25 million of capital to the Oklahoma Resource Basin to further advance our understanding of the resource potential, which already stands at over one billion oil equivalent barrels on a 2P basis.

We are complementing our two-rig operated program with incremental high-value, non-operated activity which is a very efficient way to maximize the benefits of our capital dollars. From an execution standpoint, our teams had a great first quarter. We grew production from our three U.S. resource plays 11% over the prior quarter and 49% year-over-year.

Our total E&P net production, excluding Libya, also posted strong results growing 4% and 20% respectively. All this was accomplished within our planned first quarter capital budget. We recorded 98% average operational availability for company-operated assets during the first quarter, our most economic barrels.

Yesterday, we announced a further optimization of our 2015 capital investment and exploration budget to $3.3 billion. This reduction is driven by a relentless focus on capital discipline and maintaining financial flexibility in this period of ongoing price uncertainty.

We're adjusting activity levels to manage cash flows while still delivering on our strategic objectives and our three U.S. resource plays and with no change to full year E&P production guidance.

In addition, we are continuing our commitment to ongoing portfolio management regardless of commodity cycle and are targeting non-core asset sales to generate at least $500 million in proceeds. Portfolio management is simply part of what we do as an independent E&P company.

At quarter end, cash and cash equivalents were approximately $1.1 billion, which combined with our revolving credit facility, resulted in a total liquidity of $3.6 billion. And in May, we amended the revolving credit facility to increase the available capacity from $2.5 billion to $3 billion and extended the maturity date to 2020.

Our 2015 capital program was always designed to be front-end loaded, and the first quarter of 2015 has been a quarter of transition. We are efficiently ramping down to lower activity levels in our U.S. resource plays and will achieve our target of 10 rigs by the end of second quarter.

Our current plan is to hold that activity level relatively flat for the remainder of the year, averaging a mid-teens rig count for the full year. But just to reiterate, our guidance of 5% to 7% year-over-year production growth for the total company, excluding Libya, and 20% growth for the U.S. unconventional plays has not changed.

With the enablers of lower costs, improved efficiencies and strong execution, our strategic objectives in the three U.S. resource plays remain in full force even at an overall reduced budget level. We will continue our successful Eagle Ford co-development, expanding beyond the Austin Chalk to the Upper Eagle Ford in our stack-and-frac pilot.

Our first quad stack and frac pilot, which includes one Austin Chalk, one Upper Eagle Ford, and two Lower Eagle Ford wells, is online and early performance is encouraging. We also placed five Upper Eagle Ford wells online in the quarter.

In Oklahoma, we are executing our two-rig operated program and brought five gross operated wells to sales this quarter, all in the SCOOP.

We're also continuing to leverage the benefit of our high value outside operated program and plan to participate in approximately 50 of those wells this year in the SCOOP Woodford, SCOOP Springer and STACK areas, thanks to our reallocation of budget to one of our most prospective areas.

The capital we've reallocated to Oklahoma is primarily focused on increasing our non-operated gross well exposure. This increase in capital demonstrates our belief that Oklahoma represents an exciting growth opportunity for Marathon Oil that competes very favorably with our existing portfolio.

We continue to advance our technical work here to be positioned to step up our activity as prices improve. And finally, in the Bakken, we concluded our enhanced completion pilots and have incorporated the improved design into all wells drilled this quarter. Additionally, initial results from the first of our four down-spacing pilots are encouraging.

The second pilot is currently online, but with fewer than 30 days, and the third just completed drilling. Our ultimate objective is to fully integrate the down-spacing pilot results with the now concluded completion design trials into our future development plans.

Before we open the call up to questions, I'd like to reiterate that our strong operational execution, cost reductions, continued efficiency gains and capital discipline are enhancing our returns today, have us well-positioned for the current price environment and well-prepared for a sustained commodity price recovery.

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 reprompt as time permits. With that, Vivian, we'll open the lines for questions..

Thank you. Our first question comes from Ed Westlake from Credit Suisse. Please go ahead..

Yeah. Good morning and congratulations on the strong operational momentum. And quick question on the Eagle Ford charts. I mean, I guess you did discuss it on the Q1 call but just a clarification.

How much of the EUR improvement that you're talking about is kind of high grading and how much of it is due to completions performance?.

Ed, it's a very good question, and I think you should look at it and both of the things you're referencing are important in that. First and foremost, the ongoing completions optimization we're doing is clearly driving EUR enhancement.

As we work on stage density, profit loading, fluid loading and active diversion, we continue to see improvements on that side. There is an impact as we focused in this year, particularly 2015, on a more focused area to deliver the highest returns in a lower commodity environment. So we are seeing some uplift from that.

But I would encourage you to say it's principally driven by the completions efficacy we're pushing all across those basins. That's what driving the real EUR enhancement. And I think that's reflected if you even look at the early IPs, again driving that..

Okay. And a totally unrelated question, and we won't talk about the politics of what's going on in Alberta. But the oil sands, a very solid performance in the first quarter.

Is that a sign of the sustainability that you were looking for or is that just a lucky quarter?.

Ed, not just us but our partners and Shell as operator have worked very hard over the last several years, particularly the last year to two years, really working on the reliability system. I don't think we've seen enough runtime yet to say that's sustainable. But the signs are encouraging from our perspective.

We really like the focus on operating expense, and we have more steps planned to work on that this year. Certainly, the production is a sign that, in fact, this is the fourth strong quarter in a row of production deliverability out of that business. So I think we're on that road to improvement that we haven't been able to point to before.

Again, I'd like to see more runtime, but I'm certainly encouraged by this past quarter and actually the past four quarters. That trend is headed in the right direction, and it needs to in this environment..

Yeah. Thanks very much..

And our next question comes from Doug Leggate from Bank of America. Please go ahead..

Thanks. Good morning, everybody. Lee, I wonder if I could – I don't know who actually who wants to take this one. But if I look at the results you posted in the Upper Eagle Ford, quite a wide range of 30-day IP rates there.

I'm just wondering if those wells were all of similar design or if there's some obvious kind of variance between those that caused that? And maybe just give us an update as to whether you think the type curve is moving higher or if this is really more of a high grading in 2015? Then I've got a follow-up, please..

Yeah. Well, maybe I'll offer a few comments and then let Lance weigh in. We're still in the early days of the Upper Eagle Ford co-development. I would say that we're still in the process of really delineating where the Upper Eagle Ford is going to be prospective across our acreage.

And I think as part of that delineation, we will see some natural variability in well results as we test different things in that particular play. I think overall, though, we're very encouraged from what we're seeing in the Upper Eagle Ford and in combination, of course, with the Lower Eagle Ford.

And we're seeing similar strong results in the stack-and-frac of which the Upper Eagle Ford is a component part. Maybe I'll let Lance just comment on the completion design aspect of that..

Yeah, Doug. I think Lee actually highlighted it very well. We're testing Upper Eagle Ford in a more fulsome way, spread out over a fairly large area. So we're going to see some disparate results of that as we make sure we fully delineate it. I'd say those results are very much in line with Lower Eagle Ford and Austin Chalk in the same respective areas.

And I would say what's most encouraging to us, the Upper Eagle Ford is working well in the areas where the Austin Chalk has worked a little bit less effectively. And so we see those two as increasingly interchangeable so we can co-develop in a broader area.

And very encouraged thus far on the Upper Eagle Ford both in that Northern end as well as in the stack and frac. I think, to be more clear, we brought on five Upper Eagle Ford wells that we announced that are distinctive.

And in that stack and frac pilot that came online also includes a sixth or one more incremental Upper Eagle Ford well that's performing similarly..

All right. I appreciate that. Lee, you obviously had – my follow-up is in the costs. You clearly had a very strong cost performance, and I think that's really characterized your tenure since you've been CEO.

But I guess my question is, assuming we do get a recovery in the oil price, let's assume into the $70s or something like that, how sustainable are these cost reductions? Is it dynamic with an oil price recovery, or do you expect to be able to hang on to a lot of these gains? And I'll leave it there. Thanks..

Yeah. Thanks, Doug. We are very focused on cost, and I give a lot of credit to our asset teams. And as I mentioned in my opening remarks, operating cost is just hard work. It's many things coming together to contribute to driving that unit cost lower. It's both the numerator as well as the denominator.

It's working your absolute cost as well as making sure you're keeping your barrels online, and the teams did an outstanding job at that this quarter. Many of those things, I think, in the operating cost side, though, are structural in nature.

When you think about things around preventive maintenance and our ability to efficiently deploy contractors, when you think about efficiently using our installed compression horsepower, when you think about our optimizing of our chemical programs in the oil field, all of these things, in our mind, are independent of the commodity price environment.

And we will carry those forward in time. In parallel with that, though, we're not turning a blind eye to our scale and our ability to leverage that scale in commercial dialog as well. And some of those will be more sticky than others in some cases. But we do expect that we'll retain even an element of those commercial gains as we move forward in time.

But those will have a much closer correlation with the pricing environment that we find ourselves.

On the capital side, when you think about the cost reductions we've achieved there, I mean, when you look at the $1.3 million of well in the Eagle Ford, the $1 million of well that we've achieved in the Bakken, the $600,000 we've achieved per well in Oklahoma, those capital efficiencies have, in large part, been driven by the response of the service industry to participate in this downturn that we're experiencing.

But even within that, there is a commercial element and efficiency element as well. Our most efficient frac crews can deliver a high number of stages on a monthly basis. That's a win-win for both the operator as well as the service provider.

And our ability to keep those most efficient crews running, even with the downturn in activity, I believe, will be key to our ability to continue momentum as we see prices improvements in the future..

Appreciate the answers, Lee. Thank you..

Thank you, Doug..

And our next question comes from Ryan Todd from Deutsche Bank. Please go ahead..

Yeah, thanks. Good morning, gentlemen. Great results. And if I could ask – maybe the first question is can you talk a little bit about the rationale behind the decision to drop the incremental rigs and what that means for the trajectory of 2015 production? Previously, you had talked about the U.S. onshore showing kind of an exit-to-exit incline.

Is that still the case?.

Yeah. Okay. Yeah, thanks, Ryan. Let me maybe start with the rationale around the further optimization and reduction in capital budget. I would really describe that decision and really driven by two things.

First is just a continued focus on capital discipline and financial flexibility in a period where we still have uncertainty around the price environment, albeit, we've seen some strengthening here as of late. A lot of the macro factors that have driven the downturn are still in place, so we need to recognize that.

Secondly, with the enablers of both cost efficiency and cost reduction, we're still able to achieve our strategic objectives in each of the three U.S. resource plays and hold our guidance under that revised budget and drive those efficiencies and savings, really, down to the balance sheet.

And if we start to see a sustainable price recovery, we can then reconsider if we want to take some of that cash flow and redeploy it into the business.

In terms of volumes targeting and trajectory, you mentioned that we had communicated previously an exit-to-exit in the unconventional target or unconventional production 4Q to 4Q, 2014 to 2015 slightly up on an exit-to-exit basis. And we still feel that that is consistent with the budget that we're putting forward today..

Great. And then maybe one follow-up on that. If we look at the normalized second half outlook, you've given – obviously, we have an updated CapEx budget and, like everybody else, you came into the year a bit hot.

Can you talk maybe about what the normalized CapEx run rate looks like in the second half of the year?.

Yeah. Let me maybe describe it more from an activity perspective, and I think the capital will then kind of follow, Ryan. As we talked about, you used the word we came in hot. I think we recognized that we were going to come into the first quarter at high activity levels.

We were coming out of 2014 with nominally 30-plus rigs running in the unconventionals. We started that deceleration in activity in the first quarter and, in fact, our capital budget – we delivered essentially against our capital budget in the first quarter. But we did have a momentum effect as we came in from last year. That ramp-down is continuing.

By the time we get to the end of second quarter, we'll be at our 10-rig count that we will hold flat for the remainder of the year, and that will set the activity levels in our unconventional plays..

Okay.

And any idea of what the CapEx number is associated with that 10-rig program?.

Well, again, if you kind of think about our $1.1 billion rate in the first quarter, you think about that in the context of our overall $3.3 billion budget, you put in the fact that we're relatively talking about a flat activity level from the second quarter forward, I think that you can back into the math in terms of what the actual rate will look like..

Great. Thanks. I'll leave it there..

Thank you, Ryan..

And our next question comes from Matt Portillo from TPH. Please go ahead..

Good morning, all..

Hey, Matt..

Good morning, Matt..

Just a question around capital allocation thoughts.

As you guys continue to see positive improvements in the SCOOP and STACK, can you talk about your capital allocation decisions as you think about heading into 2016 and how that may shift between the Bakken, Eagle Ford and Oklahoma asset base?.

Yeah. Absolutely. As we've talked in the past, we look at capital allocation down really to a type-curve level. And it is a competition for capital allocation amongst the three resource plays.

Specifically, when we look at the SCOOP and the STACK, and we think about incremental cash flows becoming available to reinvest in the business, we're going to drive those to the highest return opportunities. Today, when you look at our single-well economics, that's really the Eagle Ford and Oklahoma.

And the highest quality of the Bakken, the Myrmidon, and as we integrate both the completion trial results and the down-spacing results, we'll see how those fare in the capital allocation decision. But there's no doubt that as incremental capital becomes available, that will be directed to the U.S.

unconventionals and Eagle Ford and Oklahoma will be the strongest competitors for that capital..

Great. And then just a follow-up to that question, you mentioned potentially north of $500 million in non-core asset sales.

Just curious as you see a firming of the commodity price here and potential execution on those transactions, should we expect to see that redeployed potentially into the ground in the back half of this year heading into 2016 in regards to activity, or can you provide a bit of an update on how you're thinking about the capital allocation from those transactions?.

Yeah. Well, first maybe just a few thoughts on the potential transactions themselves. In our view, portfolio management is part of what we do. It's an evergreen process.

These are non-core assets that we're talking about, and what that means to us is that these are assets that are not going to compete for capital allocation and likely have higher value in someone else's portfolio.

This process would be going on irrespective of the commodity cycle that we find ourselves in because we think, again, these assets will have appeal to the right portfolio.

Assuming success in those divestment activities, then we'll look at that at that point in time and see how constructive the price environment is and make a decision as whether or not we bring that to the balance sheet or redeploy it into our organic investment portfolio, which is very competitive..

Thank you very much..

Thanks, Matt..

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

Thank you. Good morning..

Good morning, Brian..

I wanted to follow-up a little bit on some of the capital allocation questions. In SCOOP, STACK and Springer, you've reallocated capital there.

But can you talk to your preference on balancing non-operated spending versus accelerating your own spending, and specifically, what the milestones you would be looking for between price, costs and well results for you to make a more material acceleration in your operated activity levels?.

Yeah. Yeah, absolutely. Well, first of all, the two-rig operated program, beyond delivering very profitable and competitive wells, is also allowing us to protect our pretty significant leasehold position in Oklahoma, over 300,000 acres.

So that is an important element of our operated program and why we wanted to continue that commitment going into this year. There's no doubt that there's been an activity uptick in Oklahoma in our non-operated portfolio as those folks that are multi-basin operators direct more capital into Oklahoma.

We want to participate in the high-quality wells that that affords us because it simply expands the number of data points in our knowledge base around the resource potential that exists in Oklahoma.

Having said that, though, and kind of consistent with my previous comments, to the extent that we see a sustained strengthening in prices, that we see incremental cash flow come available. Oklahoma, our operated program, will compete very favorably for those incremental dollars..

Got it. Thank you. And then I have a somewhat nuanced follow-up to, I think Ryan Todd's earlier question with regards to how you are thinking about year-end.

What I'm trying to figure out is or what we're trying to figure out is whether on a going-forward basis, you are saying you can do exactly the same as previously as we look into next year but with fewer rigs.

And so I guess my question is with your 1Q having beaten expectations, you now have a little bit of a buffer to lower activity and get back to the same point in terms of year-end production that you were at before.

Is that just the case, or is what you're saying, you're going to be on a growth trajectory from the year-end point that was no different with a lower rig count than it was previously with a higher rig count?.

Yeah, I think we want to make sure that we're well-prepared to reengage and ramp up in the unconventionals. Our base plan this year is to be at our 10-rig count by second quarter. We think that is the right answer from a capital discipline standpoint.

But we have the execution capacity to step into more activity as the macro environment supports that decision, and we'll be well-positioned to do that. And one of the advantages, of course, of holding on to our best rigs, our best crew, is that it does position you very favorably to step back in to that high activity or higher activity period.

So as we look ahead to 2016, we view that as an opportunity to start that ramp-up, again, assuming that we see that constructive price environment in front of us.

And within our, of course, 2015 budget, we do have some items, some investments that will be either reduced or falling out of the 2016 program that will provide us a little bit of accommodation space even on a flat budget outlook going into 2016..

Great. Thank you very much..

Thanks, Brian..

And our next question comes from John Herrlin from Société Générale. Please go ahead..

Yeah. Hi. Just two quick ones from me.

Could you talk more about the Rodo well in EG and what your plans are there?.

Yeah, absolutely, John. We'll let Mitch take that one..

Sure, John. Thanks for the question. We talked about in our 4Q call the two-well exploration program in EG. And we previously announced the non-commercial hydrocarbon results of the Sodalita well. We did fare a bit better on the Rodo well.

But we now want to integrate the results of both of those wells into our regional database, look at the options to further exploit the other prospects in the area and understand what the commerciality options might be looking forward..

And I think just building on that, the EG program to us is a great example, though, of really infrastructure-led exploration where we have the investment there. These would be possibly smaller accumulations that we think that we have a unique ability to bring online and make commercial.

But as Mitch stated, we still have some work to do to integrate the results from both wells before we're ready to move forward. You had a second question, John..

Yeah. I did. I was wondering whether you think your current distribution is too high relative to the cash flow, your dividend, whether you need to address that going forward or given your current capital plan and asset sales that it's not an issue..

Yeah. John, this is J.R.

How are you this morning?.

Good.

And you?.

I'm good. Thanks. No, John, still, we've been pretty clear that when we think about capital allocation, that the dividend today remains in that pool of the first call on our capital. At the end of the day, the decision around the dividend is really the board's and not management. At this point in time, it remains that first call on capital.

There's no doubt in a sub-$60 or $60 commodity price environment, that it pulls on our cash flows much harder than it did when it was just a year ago. But at this point in time, we're still committed to that dividend, John..

And our goal is, of course, to grow back into it..

Great. Thank you..

Thanks, John..

And our next question comes from David Heikkinen from Heikkinen Energy. Please go ahead..

Thanks. Just curious on the production and reserves associated with the non-core assets..

Yeah. Just, we haven't detailed out specifically any granularity on those assets, but they're non-core. And for us, that means that they will likely be not significant from a volumes or resource standpoint..

Are they in you guidance or not? I guess if it's not significant, doesn't really matter..

Well, yeah. Today, of course, we don't put any potential divestments into our forward guidance..

That's helpful.

And then thinking about cadence in each of your onshore resource plays and your second quarter guidance, can you break out some idea of expectations of how you maintain the Eagle Ford at a higher activity level, and then I guess Oklahoma next, and then what happens in the Bakken as you've slowed more rapidly there? Just trying to get an idea of production in each of those as you go through the year..

Yeah. Well, just in terms of cadence or pace, it's really again driven by rig activity and frac crew activity. A case in point, David, we're already at a single rig of activity in the Bakken.

But within that single rig capacity, we are very confident that we will still be able to deliver on our downspacing pilots, which was a key strategic objective for this year in the Bakken.

In Oklahoma, our two-rig operated program was largely dictated by our desire to ensure we protected all of our high-quality leasehold while continuing to develop the SCOOP area as well. And then of course, leverage, to the extent that we can, the non-operated side of the business to leverage our capital very efficiently.

And then in the Eagle Ford, it's really taking full advantage of some of the efficiencies that we are seeing on the drilling front and hopefully being able to extrapolate those moving forward into the second half of the year..

I guess just to make simple math, if we take your gross operated wells in each area, subtract first quarter and divide by three, is that a rough approximation of completed well cadence?.

Yeah. I think it is a rough approximation because as we get down to that, we are a little bit in still that transitional period, David, as we come out of the first quarter where we're still kind of decelerating and ramping down.

But as we kind of hit the back end of the second quarter, that really is setting the pace as we look forward into the second half of the year..

Okay. That's clear..

Does that help?.

Yeah, yeah..

Okay. Thanks, David..

And our next question comes from Guy Baber from Simmons & Company. Please go ahead..

Good morning, everybody..

Hey, Guy..

Good morning..

Lee, I apologize for belaboring this point, but on the topic of pivoting back toward increasing activity levels, you've mentioned consistently that you want to see a sustainable price recovery before you begin to add rigs.

Can you just talk a little bit more about what that really means and what you want to see? Prices are at $65 a barrel on the forward curve later this year.

Do you need to see a higher price, or is it more of a duration question, or is it just a matter of you all becoming more comfortable with the macro internally? And then relatedly, you mentioned a number of times you want to be well-prepared to re-engage.

Are there any bottlenecks that you're aware of that could hinder an efficient ramp back up? And really just wondering, what risks you're most focused on mitigating in a ramp-up scenario and how you believe the company is well-positioned to ramp up whenever you feel that the time is right?.

Yeah, well, let me maybe take the question on the price outlook and what we're really looking for there from a trigger point standpoint. And then maybe I'll defer the bottleneck question around our unconventionals over to Lance.

But on the question of what is the trigger, what are the signs that we're looking for to then give us confidence to begin a ramp-up in our unconventionals. For us, you're right, the forward curve is looking around $65.

I think if we saw sustainment at $65-plus certainly going into the back half of the year in 2016, to us, it's more about seeing that being a sustainable recovery and having the confidence to come back in and begin a ramp-up.

But if we saw those levels, we felt that the macros were supportive and constructive of a sustainable $65-plus kind of a range, we feel very confident going into 2016 with a ramp-up in our unconventionals.

Let me hand over to Lance, though, to address more of the question about execution bottlenecks as we start thinking about a ramp-up in the unconventionals..

Guy, as we reduce activity, we have a clear focus on retaining the most efficient service providers, crews and equipment, which naturally creates an efficiency drive on our existing activity that remains. But it also positions us well as we grow. We have existing relationships with those providers.

Many of those are going to be the most equipped to bring equipment and people back into the sector on the growth side. So I think we're going to be comfortable there. And I think our drive to be really efficient is naturally a place where service providers would want to work for us before others. And so I think we'll have some opportunity there.

Having said that, I mean, we do have some concern that the labor force is leaving the energy space during this time, and it's going to make ramping up more challenging than ramping down. And I think that's something that, not just to us, but others will have to face in the market..

Thanks for the comments..

Thank you, Guy..

And our next question comes from Scott Hanold from RBC. Please go ahead..

Thanks. Good morning..

Good morning, Scott..

Hey, if I may just pile on again to the same theme and just maybe take a different tact.

As you look into ramping up if you do get a sustained price increase, would you all be willing to utilize your credit facility to do that, or do you have a tendency not to want to, I guess, add that to ramp up? And if I can throw in my second question right away, maybe this is a good one for J.R.

Is there any change in view on hedging because it looks like you've obviously now have some collars there with some floors.

Can you just give us a sense of how that works into the equation?.

Yes, Scott. You and I probably talked before. I don't think it's necessarily a change in view. We've always looked at commodity risk management much more broadly than just derivative usage.

But I think we've been pretty clear and transparent that if we saw opportunities in the market to protect our cash flows while still giving us a piece of that upside in the commodity price, that we'd be willing to do that.

And I think we've demonstrated it on a scale, at least, for 2015, as well as beginning to look at the 2016 market, all predominantly through the use of collars, again, to ensure that we're participating in that upside.

I mean, in terms of the balance sheet, again, arguably, I'm definitely leaning on the balance sheet this year, although I'm reinvesting the proceeds that we receive from Norway and those high-return North American unconventionals. And we've been clear that we are willing to lean, but we're not willing to stress that balance sheet.

And so it definitely is a balancing act. But don't forget, when those commodity prices do improve or as they do improve, the rest of my portfolio, that 70% weighted for oil is going to also increase my operating cash flows that then will further support our ability to reinvest in increased activity..

I appreciate the color. Thanks..

Thank you, Scott..

Thanks, Scott..

And our next question comes from Monroe Helm from Barrow, Hanley Please go ahead..

Gosh. Almost got my name as bad as David Heikkinen. It's a good thing I'm not Monroe Heikkinen. It would really be bad. My question is just kind of a follow on to what the discussion's been here about increasing activity and a better commodity price environment. So if we look at the strip for 2016, it's $65.

So let's just assume that the BTS, $65 for next year. I know you haven't done your budget for next year, but you got to have some sense of what your production profile will look like in a $65 world.

So I'm wondering if you can give us a very early outlook on what CapEx and what production might look like in 2016 under a $65 environment?.

Yeah. Luckily, it is a bit early from a budget cycle perspective. But of course, we're continuing to think about what 2016 may look like under various pricing scenarios.

But I think under the scenario that you described, which is a confident $65 firm market going into 2016, in that sense, we could take a flat budget into 2016 and still have a ramp-up in the unconventionals due to the fact that we have other investments falling away in 2015. And that would, of course, be our plan.

And then we'd watch for other signals in terms of how far we would want to go beyond that flat budget toward our ramp up in activity. But we can absolutely ramp up in the unconventionals on a flat three-three budget in 2016 in the environment that you just described..

What do you think – given that and this ramp-up in the unconventionals, could your production in the – can you give us a sense for what your U.S.

production growth might be?.

Yeah, well again, it's awfully early to talk about volume-metric growth in 2016, particularly with the dynamics that we're experiencing in the market right now.

But as we think about that flat budget and that ramp-up that it might afford in that $65 price environment, we could see 2016 average production looking not dissimilar to our 4Q 2015 exit rates..

Okay. Thank you very much..

Thanks, Monroe..

Thank you, Monroe.

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

Thanks for taking the question, guys. We haven't gotten a lot on international. So I thought I'd try a few on that front..

Excellent..

In the UK, you guys obviously had interest in the past in selling the asset. But then couple months ago, we got a positive change in the tax treatment in the UK sector.

So does that change your stance on whether this is something that you want to keep for the long run?.

Yeah, Pavel. Thanks for the question. As you said, we did entertain a marketing effort last year. We did not receive offers that we thought represented full value for the assets. And so we've taken the position that we're going to continue to operate those assets in the most efficient manner we can.

And certainly, we're focused this year in this down environment on both commercial leverage, extending some of our scale with strategic suppliers from North America across there and some structural changes.

No doubt you've seen some of the equal time rotation work we're doing, which is decreasing our overall cost structure, focused on chemicals, logistics, all of those things. And of course, the tax reforms that have been introduced in the U.K.

are helpful to us, but we're at a point in the asset life where they're not as material to us as they might be to earlier life assets..

Okay. Okay. That's useful. And then on Kurdistan, I know that there have been delays for obvious reasons with the Atrush development.

Are you incorporating any production from that field in 2015 guidance?.

Sure, Pavel. We had, in our original plan, had very minimal production from that asset. And as you've noted, we have been informed from the operator of some potential delays to first oil, which was previously targeted for the very end of 2015.

We're working through that with them and understanding the forward plan on that and look to have further updates in the near future..

Okay.

But you're still committed to keeping that?.

Well, I would just say, Pavel, just going back to our discussion around portfolio management that that's part of what we do. That includes our activities in Kurdistan as well. We'll test all assets for their fit in our portfolio.

As you can imagine with the dynamics now in the KRG, even if we were to take a position of wanting to monetize those assets it might be relatively tough. But those are assets that when we look at the above ground risk, we'll need to consider their long-term fit in our portfolio..

Right. Appreciate the color, guys..

Thank you..

And our next question comes from Jason Gammel from Jefferies. Please go ahead..

Thanks very much. I wanted to ask a little bit about the stack-and-frac. Can you talk a little bit about the actual configuration of that and if you were to move into a program, what it would mean for something like inter-lateral spacing within the lower Bakken? And then maybe talk a little bit about the cost-efficiency that comes from the process..

Sure, Jason. The stack-and-frac, we've defined it. I think, I can't remember the exact time we actually rolled that out.

But if you look at the diagram we put out in our previous press releases, we're showing that as a four-interval co-development; four vertical intervals, which is Austin Chalk, Upper Eagle Ford and then two wells in the Lower Eagle Ford.

We would actually broaden that to say that we'll have stack-and-frac pilots where there'll just be three, which is Austin Chalk, Upper Eagle Ford as well as Lower Eagle Ford. So it's that vertical co-development. We like the rates from all three of those horizons when they've been stacked.

We announced that first pilot in that, and we have some additional pilots flowing. We'll be able to talk about those as they mature. But in terms of the efficiency you're referencing there, and this opportunity, we really like the efficiency because we're co-developing all of those horizons from the same pads.

So we're spudding from rig to rig, and it gives us an opportunity to address those efficiencies. So if you look at those pilots, what you'd see is that in most of those cases, it's 40-acre spacing in the same zone. In the Lower Eagle Ford, where we have two Lower Eagle Ford wells, it's 40-acre vertical, but it's really 20-acre between them.

So it's like a chevron or a W pattern, if you will, in that lower Eagle Ford when you put two in there. But generally, same zone 40-acre with the exception of that in the lower Eagle Ford, we actually separated into, here it gets confusing, the Upper Lower Eagle Ford and the Lower Lower Eagle Ford. Creative names, I know.

So it's generally 40 acre with the exception when you put two in there in the Lower Eagle Ford, it gets to what's effectively 20-acre spacing, but they're offset in that pattern..

Okay. Thanks. That's really useful. If I could just ask one more question. There's been a lot of discussion about capital allocation over the course of the call in a low price environment. You've really had to take into stock what is important to you.

I'm just wondering how deepwater exploration now fits into your future plans just given that, even if you're successful, the amount of capital that would be required for development and the rate of return on that may not even be competitive with what were you're doing onshore..

Yeah. Well, I think there, you're hitting upon, really, the contrast between the short cycle and the long-cycle investments. And to be fair to the deepwater, you need to look at it in terms of full-cycle returns as well not incremental returns. So I guess, it really comes down to your view of that longer-term price outlook over time.

If you take a view to where that longer-term outlook is constructive, then deepwater has a role to play in continuing to meet part of the future demand. And in our view, the high-quality deepwater assets still have the ability to compete in that longer-term environment.

I think the question for us becomes one of scale and cash flows and our ability to support the large investment dollars that are required in deepwater development. And so we're going to be very selective and very focused. This year's exploration program is half of the spend that we were last year.

So we're going to bring a very sharp focus to that program that reflects the fact that these longer-cycle investments can have a role to play in your portfolio..

Okay. Appreciate the thoughts..

Yeah. Thank you..

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

Good morning..

Good morning, Jeff..

Good morning..

This is a great call. A lot of color. I wanted to ask you if you could provide a little bit more color on the Oklahoma resource non-op activity.

And what I'm really wondering is is this just mirroring operated activity without the burden of adding a rig or does it present an additional opportunity to, perhaps, compress the learning curve on areas about which you have a less defined division?.

Yeah, Jeff. It clearly accelerates the opportunities you're describing. We're learning an enormous amount from all of the offset-operated activity. That activity is predominantly focused in the highest values areas within the SCOOP and in the STACK where we have acreage. We clearly want to participate and capture that acreage and convert it to HBP.

But we also want to take and leverage all of the early production, the petrophysics and the learnings we can have from that. One of the things we really appreciate about the Oklahoma resource basins is we're getting several multiples of data from the OBO activity that we get from an operated activity for very few capital dollars.

So we're learning tremendously at very low risk, really accelerates our description of the resource, of the well productivity and allows us to design our own pilots and grow and get ready to grow to scale activity much more rapidly.

I think our increase in capital spend in that area reflects that as Oklahoma continues to be resilient in the returns it can deliver, the activity in Oklahoma has also been resilient. And we're just responding to make sure we don't miss any valuable opportunities..

And I'll also just add that even though we're excited about the incremental information that can be gained from leveraging into non-operated, we have a very good understanding of Oklahoma. I mean, we have already greater than a billion barrels of oil equivalent and 2P resource ascribed to Oklahoma.

So this is really just continuing to move that and progress that further and doing that in essentially a low price environment..

Okay. Thank you. And just as a follow-up, let's take the same thing but think of it comparatively with the Eagle Ford.

Following on your earlier remarks about well performance, was the decision to pull capital out of the Eagle Ford while increasing capital in Oklahoma an example of capital competition or was it more that Oklahoma offered a unique opportunity to increase activity without having to commit to another rig?.

Yes. I think it was, one, that Oklahoma does compete for capital very favorably. If you go back to our single well economics and you look at those even head-to-head with the Eagle Ford, those wells are on par. So strictly from an economic standpoint, absolutely competitive.

But we saw a unique opportunity in Oklahoma, I think, as Lance very well described, to really leverage our money there to continue to expand our knowledge and insight around the Oklahoma resource basin. So we felt that was a unique opportunity.

It's largely being driven by Oklahoma continuing to attract more capital from other operators' portfolios, and we want to participate in that..

Good. Thank you. That was very clear..

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

Hey. Good morning..

Hey, Roger..

Good morning..

Quite a lot of this been hit.

I guess I'd like to see if we could get any more clarity on what qualifies as non-core and is there any risk if a sale occurs this year that it would impact the production guidance? Or are we thinking about more the undeveloped, as you mentioned, competing with capital going forward?.

Yeah. Again, for a lot of reasons, we can't go into details on exactly what we would place in the non-core assets. But suffice to say, because of the definition of non-core, we view these as being not significant from a reserves and volume standpoint. So we would not view them as being highly impactful to our forward guidance.

And to the extent we're successful on those transactions, we'll communicate those clearly and transparently into the market. But for now, I think, suffice to say, we have identified a select list of non-core properties that we feel like will struggle to compete for capital, could potentially have higher value in someone else's portfolio.

And we want to pursue those and accelerate those cash flows either to the balance sheet or for redeployment..

No, it's fair.

And I guess the last question I have is as you think about reducing rig count, reducing CapEx, maintaining production, and you're seeing different ways of testing wells and completion designs, is there anything you're doing differently in terms of choking back to production or anything like that to sort of smooth out? I mean, some companies are going for more the drill but uncompleted, build a backlog.

Clearly, you're not in that camp. But I didn't know as we think about the exit rate for 2015 and all the discussion about CapEx and future drilling activity in 2016, if there was an incentive to sort of, let's call it, smooth out things a little bit as you set yourself up for the next up cycle..

Roger, we managed each of the individual wells to deliver the highest value in that investment. So we generally let the technical and operations teams manage those wells effectively. So rather than try this, for example, flow them on a smaller choke size and smooth that out. We're looking for highest value on that investment return today.

The wells we're investing in this quarter are generating good returns at current pricing. So we have confidence we can do that and decisions we've really let the technical teams make. We've scaled our activity in North America in logical increments that make sense.

So for example, in the Eagle Ford, we want to keep whole frac fleets active rather than partial frac fleets to drive efficiency. We've scaled the drilling activity to match that.

Part of the reduction we've taken in activity there is actually not just related to capital spend, but just recognizing as the efficiencies continue to improve, we were going to have to let go of one or more rigs anyway to make sure we didn't overdrill our plan for the year. And so we'll keep doing that.

I think as you noted, also, we have not been building a backlog of drilled but uncompleted wells for use later in the year. We're really managing that as an operations basket of wells to complete to manage our stimulation operation smoothly and efficiently..

Okay. That's helpful. Thank you..

Thanks, Roger..

And our last question is a follow-up from Ed Westlake from Credit Suisse. Please go ahead, sir..

I've got 10 follow-ups but I'll limit it to one. I'm surprised we haven't been talking more about the SCOOP and STACKS, so maybe people aren't quite as (59:00) as I thought.

But let me ask you about when do you think you'll be able to give us an update, just in terms of timing, in terms of the well costs in a development mode? And then appreciate that the Meramec is quite thick up in the STACK, and obviously, you've got the Woodford spring occurred about an opportunity in the south.

So the spacing could be really quite tight.

So when do you think you'll be able to give us some updates on these spacing tests?.

Yeah, when we typically talk about production results with you, Ed, we tend to talk about wanting to get 180 days of production to really understand well performance, understand where we are on a specific type curve. We are still on the learning curve in Oklahoma when it comes, though, to D&C costs.

And we think we're starting in a much more favorable position because of all the good work that has been done already in the Eagle Ford and the Bakken to drive well costs down. We captured $600,000 in well costs already since we released our new well costs this year and our single-well economics.

But we think there's a lot more room to maneuver there from both an efficiency as well as a commercial standpoint. And that's just going to take some time as we grow to scale. Bear in mind, Ed, we had plans that had actually ramped up the six rigs in the Eagle Ford at year-end – I'm sorry – in Oklahoma at the end of the year here.

And so the execution capacity is there. And I think as we move that to scale, that is going to allow us to really accelerate on that learning curve particularly when it comes to D&C costs..

Right. I was just trying to see if I could see if there was a NASCAR track in Oklahoma but so there'll be an Analyst Day at some point in the future..

We'll work on that one, Ed..

Okay. Thank you..

Thanks, Ed..

And I'm not showing any further questions. At this time, I will now turn the call back over to Mr. Chris Phillips for closing remarks..

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

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