馬拉松石油 (MRO) 2015 Q1 法說會逐字稿

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.

Thanks, Chris, and glad to have you back on the calls. Let me add my good morning to everyone. I'd like to open with just a few comments regarding the elements of our business that we control -- cost, 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 cost 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 in the 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 US 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. Finally on G&A, we have taken the necessary steps to scale our organizational capacity to match our activity level, and our first-quarter work force 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 deliver pace-setter 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 1 billion oil equivalent barrels on a 2-P 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 US 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 in our three US 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 our 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. 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 US 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.

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 US unconventional plays, has not changed. With the enablers of lower cost, improved efficiencies, and strong execution, our strategic objectives in the three US 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, and our stack and frac pilots. Our first Quad stack and frac pilot, which includes one Austin Chalk, one Upper Eagle Ford, and two Lower Eagle Ford wells, is on line and early performance is encouraging. We also placed five Upper Eagle Ford wells on line 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 are 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 re-allocation of budget to one of our most prospective areas.

The capital we've re-allocated 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.

Finally, in the Bakken, we've 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 on line, 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 our 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, I'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, Vivian, we'll open the lines for questions.

Thank you. We will now begin the question-and-answer session.

(Operator Instructions)

Ed Westlake, Credit Suisse.

Good morning, and congratulations on the strong operational momentum. A quick question on the Eagle Ford charts. I guess you did discuss on the Q1 call, but just a clarification. How much of the EUR improvement that you're talking about is high grading, and how much of it is due to completions performance?

Ed, it's a very good question. 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's driving the real EUR enhancement. I think that's reflected if you even look at the early IPs again driving that.

Okay, and then totally unrelated question. 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 shales operator have worked very hard over the last several years, particularly the last year to two years, really working on the reliability systems. I don't think we've seen enough run time 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. I think we're on that road to improvement that we haven't been able to point to before. Again, I'd like to the more run time, 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.

Yes. Thanks very much.

Doug Leggatte, Bank of America.

Thanks. Good morning, everybody. Lee, I wonder if I could -- I don't know 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 wondering if those wells were all of similar design, or if there's some obvious variance between those that caused that? Maybe 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? I've got a follow-up please.

Maybe I'll offer a few comments, and 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. 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, in combination of course with the Lower Eagle Ford. 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 comment on the completion design aspect of that.

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

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. We see those two as increasingly interchangeable, so we can co-develop in a broader area. 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 our distinctive, and that Stack and Frac pilot that came on line, also includes a sixth, or one more incremental Upper Eagle Ford well that's performing similarly.

I appreciate that. Lee, you obviously had -- my follow-up is in the costs. You clearly had a very strong cost performance. I think that's really characterized your tenure since you've been CEO. 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? I'll leave it there, thanks.

Thanks, Doug. We are very focused on cost, and I give a lot of credit to our asset teams. 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 on line, 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 preventative 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.

Parallel with that, though, we're not turning a blind eye to our scale and our ability to leverage that scale in commercial dialogue, as well. 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, when you look at the $1.3 million a well in the Eagle Ford, the $1 million a 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 down-turn 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 they win-win for both the operator as well as the service provider. Our ability to keep those most efficient crews running, even with this down-turn in activity, I believe will be key to our ability to continue momentum as we see price improvements in the future.

Appreciate the answers, Lee. Thank you.

Ryan Todd, Deutsche Bank.

Thanks. Good morning, gentlemen. Great results. 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 US onshore showing an exit-to-exit incline. Is that still the case?

Yes. Okay, yes, thanks Ryan. Let me maybe start with the rationale around the further optimization and reduction in the capital budget. I would really describe that decision 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 late, a lot of the macro factors that have driven the down-turn are still in play, so we need to recognize that.

Secondly, with the enablers of both cost efficiency and cost reductions, we're still able to achieve our strategic objectives in each of the three US resource plays, and hold our guidance under that revised budget, and drive those efficiencies and savings really down to the balance sheet. 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. We still feel that that is consistent with the budget that we are putting forward today.

Great. 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?

Yes. Let me 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 level. We were coming out of 2014 with not only 30-plus rigs running in the unconventionals, we started that deceleration in activity in the first quarter. In fact, our capital -- we delivered essentially against our capital budget in the first quarter, but we did have a momentum affect 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. That will set the activity levels in our unconventional plays.

Okay. Any idea what the CapEx number is associated with that 10-rig program?

Again, if you 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 putt in the fact that we're relatively talking about a flat activity level from the second quarter forward, I think you can back into the math in terms of what the actual rate will look like.

Great, thanks. I'll leave it there.

Matt Portillo, TPH.

Good morning, all.

Good morning, Matt.

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?

Absolutely. As we've talked in the past, we look at capital allocation down really to a type-curve level. 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. 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 US unconventionals, and Eagle Ford and Oklahoma will be the strongest competitors for that capital.

Great. Then 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?

Yes, first maybe a few thoughts on the transactions or 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. 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 re-deploy it into our organic investment portfolio, which is very competitive.

Thank you very much.

Thanks, Matt.

Brian Singer, Goldman Sachs.

Thank you, good morning.

Good morning, Brian.

I wanted to follow up a little bit on some the capital allocation questions. In SCOOP, Stack, and Springer you've re-allocated 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, cost, and well results, for you to make a more material acceleration in your operated activity levels?

Yes, absolutely. First of all, the two-rig operated program, beyond delivering very profitable and competitive wells, is also allowing us to protect our pretty significant lease-hold position in Oklahoma, over 300,000 acres. 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 up-tick 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 consistent with my previous comment, 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. I have a somewhat nuanced follow-up to I think Ryan Todd's earlier question with regards to how you're 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're saying you can do exactly the same as previously as we look into next year but with fewer rigs?

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 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 the lower rig count than it was previously with the higher rig count?

Yes. I think we want to make sure that we're well-prepared to re-engage 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. 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 into that higher-activity period.

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. 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.

John Herrlin from Societe Generale.

Hi. Two quick ones for me. Could you talk more about the Rodo well in EG, and what your plans are there?

Yes, 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. 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.

I think 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 on line 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?

Yes, 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?

John, this is J.R. How are you this morning?

Good, and you?

I'm good, thanks. John, 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. But at this point in time, it remains that first call on capital. There's no doubt in a sub-$60 or a $60 commodity price environment that it pulls 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.

Our goal is of course to grow back into it.

Great, thank you.

Thanks, John.

David Heikkinen, Heikkinen Energy.

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

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

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

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

Yes, that's helpful. 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 Oklahoma next, and then what happens in the Bakken as you've slowed more rapidly there? I'm just trying to get an idea of production in each of those as you go through the year?

Yes. 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 down-spacing pilots, which was a key strategic objective for this year in the Bakken.

In Oklahoma, our two-rig program, 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; then of course leverage to the extent that we can the non-operated side of the business to leverage our capital very efficiently. 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.

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?

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

Does that help?

Yes.

Okay. Thanks, David.

Guy Baber, Simmons & Company

Good morning, everybody. Lee, I apologize for belaboring this point, but on the topic of pivoting back toward increasing activity levels, you mentioned consistently that you want to see a sustainable price recovery before you begin to add rigs. Can you talk a little bit more about that really means, and what you want to see? Prices are at $65 a barrel in the forward curve layer 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.

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? Really wondering what risks your 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?

Yes. 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 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 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 the question about execution bottlenecks as we start thinking about a ramp-up in the unconventionals.

Guys, we've reduced 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 sectors on the growth side. We think we're going to be comfortable there.

I think our drive to be really efficient is naturally a place where service providers would want to work for us before others. I think we'll have some opportunity there. Having said that, 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. I think that's something that not just us, but others will have to face in the market.

Thanks for the comments.

Thank you, Guy.

Scott Hanold from RBC.

Thanks, good morning.

Good morning, Scott.

If I may just pile on again to the same theme, and 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 add that to ramp up? 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? It looks like you've obviously now had some collars there with some floors. Can you 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 up side in the commodity price, that we'd be willing to do that. 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 up side.

I mean in terms of the balance sheet, again arguably, I'm definitely leaning on the balance sheet this year, although I'm re-investing the proceeds that we receive from Norway and those high-return North American unconventionals. We've been very clear that we are willing to lean, but we're not willing to stress that balance sheet. 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's 70% weighted for oil is going to also increase my operating cash flows that then will further support our ability to reinvest and increase activity.

I appreciate the color, thanks.

Thank you, Scott.

Monroe Helm, Barrow Hanley.

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. (laughter) My question's a follow-on of what the discussion's been here about increasing activity in a better commodity price environment. If we look at the strip for 2016 at $65, so let's assume the WTI $65 for next year. I know you haven't done your budget for next year, but you've got to have some sense of what your production profile will look like in a $65 world. I'm wondering if you can give us very early outlook on what CapEx and what production might look like in 2016 under a $65 environment?

Absolutely, 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. I think under the scenarios that you describe, 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. That would of course be our plan.

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 3-3 budget in 2016 in the environment that you just described.

What do you think -- given that, and you would ramp up in the unconventionals, could your production -- can you give us a sense for what your US production growth might be?

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. 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.

Pavel Molchanov, Raymond James.

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

Yes, 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, so we've taken the position that we're going to continue to operate those assets in the most efficient manner we can.

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. Of course the tax reforms that have been introduced in the UK 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, that's useful. 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. 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?

I would just say, Pavel, going back to our discussion around portfolio management, 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 modify those assets it might be relatively tough. Those are assets that when we look at the above-ground risk, we'll need to consider their long-term fit in our portfolio.

All right. Appreciate the color, guys.

Jason Gammel, Jefferies.

I wanted to ask a little bit about the Stack and Frac. Can you talk about the actual configuration of that, and if you were to move into the program, what it would mean for something like inter-lateral spacing within the lower Bakken? 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 pulled 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 will just be three, which is Austin Chalk, Upper Eagle Ford, as well as Lower Eagle Ford. 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. We have some additional pilots flowing, and we'll be able to talk about those as they mature. But in terms of the efficiency you're referencing there, in this opportunity we really like the efficiency, because we're co-developing all those horizons from the same pad, so we're spudding from rig to rig. It gives us an opportunity to address those efficients.

If you look at those pilots, what you would see is that in most of those cases it's 40 well -- excuse me, 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. 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 separate it into -- here it gets confusing -- the Upper Lower Eagle Ford and the Lower Lower Eagle Ford. Creative names, I know. 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.

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's important to you. I'm just wondering how deep-water exploration now fits into your future plans, 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 you're doing on shore?

Yes. I think there you're hitting upon really the contrast between the short-cycle and the long-cycle investments. To be fair to the deep water, you need to look at it in terms of full-cycle returns, as well, not incremental returns. 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 deep water has a role to play in continuing to meet part of the future demand.

In our view, the high-quality deep-water 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 deep-water development. 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. 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. I appreciate the thoughts.

Jeffrey Campbell, Tuohy Brothers.

Good morning. Great call, a lot of color. I wanted to ask you if you could provide a little bit more color on the Oklahoma resource and non-op activity. 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 vision?

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 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. It 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. We're responding to make sure we don't miss any valuable opportunities.

I'll also add that even though we're excited about the incremental information that can be gained from leveraging in to non-operate, we have a very good understanding of Oklahoma. I mean, we have already greater than 1 billion barrels of oil equivalent in 2-P resource ascribed to Oklahoma. This is really just continuing to move that and progress that further, and doing that in essentially a low-price environment.

Okay, thank you. 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?

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. 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. 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.

Thank you. That was very clear.

Roger Read, Wells Fargo.

Good morning. Quite a lot of this has been hit. I'd like to see if we can get any more clarity on what qualifies as non-core? Is there any risk if a sale occurs this year that it would impact the production guidance? Are we thinking about more the undeveloped, as you mentioned, competing with capital going forward?

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. We would not view them as being highly impactful to our forward guidance. 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 re-deployment.

No, that's fair. The last question I have is as you think about reducing rig count, reducing CapEx, maintaining production, and your seeing different ways of testing wells and completion designs, is there anything you're doing differently in terms of choking back the production or anything like that to smooth out? Some companies are going for more the drill but uncompleted bill to backlog. Clearly you're not in that camp. 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 let's call it smooth out things a little bit as you set yourself up for the next up cycle?

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

We've scaled our activity in North America in logical increments that make sense. For example, in the Eagle Ford we want to keep hold fracfully tactive rather than partial fracfullies to drive efficiency, and 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 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 over-drill our plan for the year. We'll keep doing that.

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.

Ed Westlake, Credit Suisse.

I've got 10 follow-ups but I'll limit it (laughter) to one. I'm surprised we haven't been talking more about the SCOOP and Stack. Maybe people aren't quite as (inaudible - accent) as I thought. 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 Merrimack is quite thick up in the Stack. Obviously you've got the Woodford Spring occurred about an opportunity in the south. 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?

When we've typically talked about production results, 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 though on the learning curve in Oklahoma when it comes, though, to D&C cost.

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 cost down. We captured $600,000 in well cost already since we released our new well costs this year in 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. That's going to take some time as we grow to scale.

Bear in mind Ed, we had plans and had actually ramped up to six rigs in the Eagle Ford at year end -- I'm sorry in Oklahoma at the end of the year here. 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 cost.

All right. I was just trying to see if I could see if there was a NASCAR track in Oklahoma, so there'll be an analyst there at some point in the future. (laughter)

We'll work on that one, Ed.

Okay, thank you.

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.

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