馬拉松石油 (MRO) 2014 Q4 法說會逐字稿

Welcome to the Marathon Oil Corporation 2014 quarter-four earnings and 2015 capital budget conference call. My name is Vivian, and I'll be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded. I will now turn the call over to Mr. Zack Daley. Mr. Daley, you may begin.

Thanks. Good morning, and welcome to Marathon Oil Corporation's fourth-quarter and full-year 2014 earnings and 2015 capital budget conference call. I'm Zack Daley, Director of Investor Relations. Also joining me on the call this morning are Lee Tillman, President and CEO; J.R. Sult, Executive Vice President and CFO; Mitch Little, Vice President, International and Offshore E&P Operations; and Lance Robertson, Vice President, North America Production Operations.

As has been our custom, we released prepared remarks last night in connection with the earnings release. You'll find those remarks and the associated slides on our website at marathonoil.com.

We'll begin this morning with additional prepared remarks discussing our 2015 capital, investment and exploration budget. We issued a separate press release detailing our 2015 capital program last evening. And we posted a second slide presentation to our website, earlier today that accompanies this morning's prepared remarks. This morning's slide deck can be found under the quarterly earnings or events tabs on the Investor Center page of our website, and is titled 2015 Capital Budget Slide Deck. After our remarks, the remainder of the call will be available for Q&A. As a reminder, today's call is being recorded.

Slide 2 contains a discussion of forward-looking statements and other information included in this presentation. Our remarks and answers to questions will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

In accordance with the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2013 and other filings with the Securities and Exchange Commission, cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

With that, I'll turn the presentation over to Lee Tillman, Marathon Oil President and CEO, who will begin on slide 3.

All right, well, thank you, Zack, and good morning to all. I will say Zack is pitch-hitting for Chris Phillips today, who is a bit under the weather. We hope Chris is back with us soon.

As Zack mentioned, yesterday afternoon we released our fourth-quarter and full-year 2014 earnings, as well as announcing our 2015 capital budget. What we really want to accomplish this morning is to spend the bulk of our time on the 2015 capital budget, and then turn to your questions.

But before I do that, I'd like to share just a few thoughts on our full-year 2014 results. I think I would summarize by saying, we delivered against our 2014 performance commitments, investing in our three, high-return US resource plays, which yielded a 35% increase in production. We successfully closed on really two significant strategic dispositions of over $4 billion in proceeds. And we were also able to return value to our shareholders through an increased dividend and $1 billion in share repurchases.

We also had a proved reserve replacement ratio of 183%, ex dispositions, and that was at a very competitive $20-per-barrel oil equivalent in finding and development cost. And we also recorded 97% operational availability across our Company-operated assets. And of course, these are our most economic barrels.

I think we would say that by any measure, it was an outstanding year. But the second half of the year brought us a bit of a new reality, a bit of a gut check. Commodity prices corrected significantly downward. And I think we were harshly reminded yet again of our inability to predict pricing.

Our business plans for 2015, as with others, were being essentially adjusted in real time as the market continued to search for some semblance of stability. And in December, we felt it was critical to at least advise our shareholders as to our view of 2015 capital budget guidance at that particular point in time, with the caveat that we were prepared to respond to further downward movement in pricing.

Our foreshadowing, unfortunately, was quite accurate, and prices fell more as we moved into the new year. This morning, what we are sharing is our updated plan and budget, based on today's view of the pricing environment. But it has the same caveat that flexibility is going to be essential in a volatile commodity market. We will admit that we're no more clairvoyant on pricing than we were in December.

So with that little bit of a preamble, let me go ahead and turn to 2015. Our $3.5 billion budget really emphasizes investment selectivity and returns, balance sheet flexibility, and positions us for price recovery. It is a further 20% reduction since our December update. We've significantly reduced exploration spending by half. And we are moderating activity levels in the US in alignment with good cash flow management.

We'll end up directing about 70% or $2.4 billion of our budget toward our three core US resource plays. And these continue to be among our highest-return investment opportunities. Our objective is simple. It's to deliver high returns in the current pricing environment, while we protect our financial flexibility through prudent management of cash flows.

Today we're also releasing updated single-well economics for the resource plays. And these new single-well economics reflect our 2015 inventory high-grading, along with the service cost reductions that we've already captured and have in hand. Suffice to say, we are not opportunity-limited.

Furthermore, we're continuing to pursue all means to expand our margins. We're going to do this through capital efficiency, expense management and operational reliability -- those things that we can control. Marathon Oil clearly benefits from a deep multi-year inventory that is robust across a broad range of pricing scenarios. Given this portfolio, we're fortunate to have the optionality to adjust our short-cycle investments in line with commodity prices.

As we continue to focus on our three high-quality US resource plays in 2015, our budget and activity plans will support high-return investments that will in turn generate a total Company production growth rate, ex Libya, of 5% to 7% year over year. And specifically for our resource plays, a growth rate of about 20% year over year, admittedly benefiting from the 2014 carry-in effect.

Bottom line is that we are going to be driven by returns and cash flow management, with growth as an outcome, while we retain the ability to flex on pricing. With that, I'll turn over to Lance Robertson, our Vice President of North America Production Operations, and he'll take us through our activity plans for the resource plays. Lance?

Thanks, Lee. I'll begin on slide 4. In the context of the current environment, we are prudently reducing development activity and commensurate capital expenditures across all three of the resource plays. Having the flexibility within our existing commercial agreements allows us to make these adjustments readily and at little to no cost.

As reflected by the table in the top right of the slide, activity will be reduced from 33 active rigs at the end of 2014 to 18 by the end of the first quarter, with a further reduction to 14 rigs by the end of the second quarter. We anticipate continuing at the 14-rig pace across the balance of 2015, but retain significant flexibility to scale up or down as market conditions warrant.

In addition to rig reductions, we are optimizing completions activity to match our inventory of wells, with a focus on maintaining the execution efficiency of full frac fleets. In addition to driving operational efficiencies, we have focused extensively on service cost reductions in this environment, securing to-date a minimum of $225 million in savings across the 2015 activity.

Importantly, substantially all of these initial savings were effective in January, benefiting our returns early in the cycle. We continue to see opportunity for additional savings throughout the year, further protecting our cash margins.

Our North America opportunities for investment remain compelling at current commodity pricing. Referencing in the bottom right, our 2015 investments will focus on inventory that can deliver strong returns in each of Eagle Ford, Bakken and the Oklahoma Resource Basins. In addition, we have multiple years of inventory that can deliver similar returns at today's pricing.

With our core position in three key basins and a relentless focus on continuing to drive efficiencies and cost savings, we can continue to provide Marathon Oil with opportunities to deliver value to our shareholders. The 2015 development spend and activity in the resource basins will result in a production increase of approximately 20% year on year, with fourth-quarter 2015 exit rates up from the same quarter of 2014.

Turning to slide 5, we'll focus initially on the Eagle Ford, where we have allocated approximately 40% of total 2015 capital on our high-return inventory. Our quality core acreage provides opportunity to drive tremendous value at this scale. We continue to realize this value through highly effective execution.

With these efficiencies and recently secured service cost reductions, our costs have fallen by $1.3 million a well, to an average of $6.3 million a well in 2015, maintaining our position as one of the most cost-efficient operators in the basin. Over the past year, completions optimization has resulted in a 25% increase in 180-day cumulative production across wells to sales. This incremental early-life production materially improves well margins. And as this group matures, we anticipate adding further value, with an increase in ultimate volumes recovered.

Taking into account cost savings and improvements in well performance, we anticipate drilling approximately 215 to 225 wells this year in South Texas, with returns ranging from 40% to 60%, at $60 flat WTI pricing. This group includes Eagle Ford condensate wells, high GOR Eagle Ford oil wells, with the remaining 25% of wells to develop and further delineate the Austin Chalk. In all cases, the Austin Chalk is co-developed with the Lower Eagle Ford, leveraging the existing gathering network and the facilities.

Focusing on the table in the upper left, we're illustrating for the first time, single-well metrics for the Austin Chalk. From the data you can see that the initial production and estimated ultimate recovery compare favorably to the Eagle Ford condensate and high GOR oil wells. In the currently delineated core area, the Austin Chalk wells deliver the highest returns, driven by higher early-life cumulative production relative to other horizons in the Eagle Ford portfolio.

Continuing with our co-development efforts, the first four Upper Eagle Ford wells were placed on sales in the first quarter. They're co-developed above high GOR Lower Eagle Ford oil wells. And this pilot, consistent with the Austin Chalk co-development efforts -- same zone spacing is 40-acre equivalent, with spacing between the horizons at 20-acre equivalent. These wells are early on flow, but initial rates and pressures are encouraging from both horizons.

We will continue this testing throughout the year, much in the way the Austin Chalk has been and will continue to be identified, evaluated and developed. In addition, we also spud the first stack and frac co-development pilot in the fourth quarter, including Austin Chalk, Upper Eagle Ford and two wells in the Lower Eagle Ford. We will provide an update on these efforts later in the year.

Focusing on the Bakken on slide 6, the initial completion trials are mostly finished, with 42 of the wells completed and flowing to sales. Of these wells, the first 18 in Myrmidon and Hector have yielded a more-than 30% increase in cumulative production over the first 60 days. This material change in early production is clearly very encouraging, and we anticipate further updates as the production histories mature.

In the aggregate, the incremental spend on more intensive completions is yielding a return on investment at or above 100% in all areas and zones. As a result of strong early production response and our focus on driving value, we've adopted the updated completion practices, with more intensive stimulations into the base program. These changes are effective across Myrmidon and Hector in Middle Bakken and Three Forks intervals. Reflecting the success, we will continue to test and optimize completions moving forward.

Directing your attention to the single-well returns table in the upper left of the slide, we illustrated updated gross completed well costs of $6.2 million to $6.6 million a well, reflecting a reduction of almost $1 million a well thus far. These costs include incremental spend for more intensive stimulations for each area. But the full-performance benefits of enhanced completions on EUR is not yet reflected.

In addition to the completion pilots, we have concluded drilling on the first two spacing pilots, with six wells per horizon in Hector and Myrmidon. These pilots will move to completions over the coming weeks, with the third spacing pilot currently drilling.

We anticipate a combination of improved stimulation designs, coupled with increasing spacing density, to drive toward the highest value -- incrementally improving the recovery efficiency across a drilling unit. With improved well costs and higher initial production, our investments in the Williston Basin will deliver competitive returns of 20% to 30% in the current commodity environment. As we continue to focus on highest returns and value, the majority of our activity in 2015 will occur in the Myrmidon area.

On slide 7, Oklahoma Resource activity will focus on protecting core leaseholds in the SCOOP and STACK areas. With more than 70% of our Oklahoma acreage held by production, our 2015 activity will allow us to manage lease expirees with moderated spend of approximately $225 million in two rigs after the first quarter.

Our focus for the year will include high-value SCOOP and STACK wells, including our first operated spacing pilot in the SCOOP-Woodford, where we are targeting six wells in a 640-acre unit, effectively testing same-zone spacing of approximately 105 acres. This spacing pilot was spud in the fourth quarter. We anticipate moving to completions by the middle of 2015.

In addition, we will spud our first operated Springer well in the SCOOP area later in the year to complement the 17 outside-operated Springer wells in which we currently participate. We continue to grow our leasehold in Oklahoma, adding 10,000 net acres focused on the SCOOP and Springer areas, in the fourth quarter.

Drawing your attention to the table in the upper left, SCOOP well estimated ultimate recoveries continue to be among the highest available, with the high liquids content. Having secured an initial cost reduction of more than $0.5 million, we can confidently deliver wells with 30% to 40% internal rates of return in the current commodity market.

With the lower activity in Oklahoma, we'll turn our focus to developing the spacing pilots, driving efficiency, securing additional cost reductions, and delivering higher ultimate value. With the longest wells from spud to total depth in our resource portfolio today, we see ample opportunity for cycle time improvements in 2015. And with price recovery, we'll be ready to move to scale at the lowest cost.

Slide 8 brings together all three US resource plays and demonstrates the strength of our resource and inventory. Our 2015 capital development program is one that appropriately scaled to today's commodity price environment. As Lee mentioned at the beginning, we expect these basins to achieve an approximate 20% increase in production, 2015 over 2014, taking into account our spending plans and moderated activity levels.

Next, I'll hand it off to my counterpart, Mitch Little, Vice President of International and Offshore E&P Operations. Mitch will describe 2015 activity for his business.

Thank you, Lance. Switching now to our international and offshore activities, which begin on slide 9, our 2015 development activities are focused on high-return, previously sanctioned long-cycle commitments and selective other projects that offer superior risk adjusted returns, including targeted activities in Equatorial Guinea, the Kurdistan region of Iraq, US Gulf of Mexico and the UK North Sea.

Within EG, we're progressing the Alba B3 Compression Project, which adds important infrastructure, allowing us to access the field's proven reserve base by significantly lowering field abandonment pressure. The project is approximately 60% complete, remains within budget and on track for a 2016 start-up. Combined with the addition of the C-21 Infill producer, the project is expected to maintain field production plateau for an additional two years, while extending field life by as much as eight years.

Our investment activities in EG also include a second near-field wildcat well, testing an oil-prone amplitude-supported prospect at Rodo, which is located within sub-area B of the Alba block. While the recently drilled Sodalita West well did not encounter commercial hydrocarbon quantities, we were encouraged by the presence of high-quality oil in multiple stacked sands. Our upcoming Rodo well is targeting a younger reservoir section, and we have several additional prospects across our more than 120,000 net acres under contract in EG.

Our UK investment program is concentrated on the addition of three Infill producers that add high-return incremental barrels to our existing operations. The first well, an Infill producer at South Brae, will be online within the first quarter, and follows on the success of two previous wells that were brought online in late 2014 and continue to outperform pre-drill expectations.

Activities also include drilling and completion of two subsea Infill producers within our operated West Brae field. The first of these wells is expected to be online by the end of February, with the second coming online around mid-year.

Moving on to our planned 2015 Kurdistan investment program, which includes the development activities highlighted here, as well as exploration activities, which will be discussed on the subsequent slide. Within the outside-operated Atrush block, construction and installation of the Phase 1 production facilities continues, with first production currently forecast for late 2015.

Appraisal and testing activities also continue in the eastern portions of the field and results from those activities will be integrated with existing data to inform a future decision regarding the applicability of additional development phases.

The outside-operated Sarsang block is currently producing around 4,000 gross barrels of oil a day, from a single-well facility within the Swara Tika field. The phased field development plan is under review within the Kurdistan Ministry of Natural Resources, and we anticipate approval and associated development activities in 2015. Finally, in the Gulf of Mexico, we're participating in the two-well subsea development project at the outside-operated Gunflint, with first production expected in 2016.

Moving now to slide 10, we have materially reduced our global exploration spending in 2015, with activities focused towards ongoing appraisal activities and/or prior commitments. The majority of this spending is tightly focused within two geographic areas.

Within the Gulf of Mexico, we continue evaluation and testing of our prospect inventory within the inboard Paleogene play. Several discoveries have been announced within the play over the past few years, including outside-operated Shenandoah field, where Marathon Oil holds a 10% working interest. An appraisal well is expected to spud at Shenandoah in the second quarter. Additionally, the Maersk Valiant drill ship will be back for our second operated well slot sometime during the second quarter of 2015.

Moving over to Kurdistan, we are currently drilling the Mirawa 2 appraisal well within the Company-operated Harir block. The well is a follow-up to the 2013 Mirawa discovery well, and will further define the resource base in advance of a commerciality decision, which is due later this year.

In addition, within the outside-operated Sarsang block, the East Swara Tika exploration well is currently being side-tracked to an up-dip location. Well results are expected to be announced later in 2015.

With that, I'd like to turn the call back to Lee for his concluding comments.

All right, well, thank you, Mitch, and thank you to Lance, as well. As our budget and activity plans demonstrate, Marathon Oil is focused on delivering long-term shareholder value, regardless of the commodity price cycle. We have a keen eye on returns and financial flexibility. We're committed to exercising capital discipline that will protect our optionality and position us to be a stronger E&P in not only 2015 and 2016, but beyond. Our three US resource plays have exceptional subsurface quality and strong single-well economics that will deliver solid returns across a broad range of price scenarios.

Even after high-grading our opportunities for this low-price environment, our deep portfolio affords us a multi-year drilling inventory, with pace and spending levels ultimately moderated, based on pricing and cash flows. We are exercising every means available to expand our margins, including significant contributions that you've heard about, from enhanced completions and service cost reductions.

But we're also mindful of driving the fundamentals of expense management, including organizational capacity, which must match the current environment and activity levels. And finally, operational reliability. Our commitment to our previously stated seven strategic imperatives is durable, regardless of the commodity cycle.

Though we're rightly focused on prudent near-term actions, we've laid the groundwork for the future, and we'll continue building on our resource base. In 2015, our asset teams will be aggressively testing co-development, stack and frac, down-spacing, enhanced completion designs, and new horizons -- all strategic opportunities to expand our unconventional resource for the future.

We are well-prepared for the current low-price environment, and our 2015 investment program is based on achieving the highest returns at today's commodity prices, while prudently managing cash flows. We will also continue to protect optionality to flex our spend up or down. And we'll ensure that our outstanding asset teams are prepared to take full advantage of the sustained recovery.

That really concludes our prepared remarks. So operator, we'll now open up the call for questions.

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

(Operator Instructions)

Ed Westlake, Credit Suisse.

Good morning, gentlemen, and congratulations on the operational performance last year. And thanks for a lot of color in the presentations.

I guess a question on the 2015 and then 2016 shale growth. I mean, you mentioned that you have inventory and you can see it in the numbers, if you look at well completions and then wells to sales, which obviously fall less. As you roll forward into 2016, if you just kept the same level of activity, what sort of production growth do you think you'd get from each of your plays? It feels like it should flatten, and then perhaps even decline, if we carried on at this level of well completions.

Let me address that one, Ed. First maybe it's useful for us just to reflect on how we developed this year's plan. It was really looking at the near-term pricing environment, the returns that we could generate, high-grading the inventory, and then testing that against our cash flow management objectives.

And really when we did that, growth became an outcome, if you will, from that process. And we tested that, of course, against numerous pricing scenarios. If we look at 2015, as we stated in the prepared material, Ed, we're looking at overall growth on average of 5% to 7% for the portfolio.

But we also believe the resource plays will deliver approximately 20% in growth. If we think about that in terms of exit rates, the exit rates, 4Q 2014 to 4Q 2015, and the resource plays will actually be up. And the overall portfolio will essentially be flat on exit rate, with the resource plays essentially offsetting our more mature properties.

Looking forward into 2016 -- and as you might imagine, Ed, we've run numerous scenarios looking at not only 2015, but also 2016, under many, many price decks, over the last few months. But when we think about 2016 and we think about a moderate level of recovery in 2016, we think that we can hold our budget essentially at current levels, 2015-type levels, around the $3.5 billion. And keep our overall average for the portfolio essentially flat, with likely exit rates increasing a bit year on year as we see a little bit more activity because we're seen some improvement in cash flows.

That's very helpful, and probably more guidance than we'll get from other companies at this stage, so thank you. And then on the cost side, $225 million across your budget, that sort of 5%, 6%, people are thinking service cost deflation is going to be 20% or more. I'm just worried if you -- I'd like to ask whether you think 20% is realistic, or is it just a function of where you are in the year?

Sure, Ed, good question. I think I would encourage everyone to think of that initial cost savings of $225 million as the minimum. Those are effectively savings we've already accomplished. They're in the rear-view mirror from our perspective, and we're working on the next level. We've built those into our budget plan, so they're included in there. We're already working on several areas of next cost savings. So we fully anticipate that savings to grow throughout the year. We're confident in what we've already achieved, and we're confident we'll achieve further savings throughout the year, Ed.

Thank you.

Doug Leggate, Bank of America.

Thanks, good morning, everybody. Lee, thanks for all the guidance and the detailed review on the capital budget. But my question is, one of your competitors this morning, who is also a very large operator in the Eagle Ford, has come out and basically said, we're just not going to give this stuff away in this oil price environment, especially when we haven't had the costs come down yet. If I read your interpretation correctly, what you're basically saying is, we're going to try and get the best returns in the current oil price environment.

Why complete the wells at all when you haven't had the cost reductions to the scale that most people are expecting? And I think by your own words, you anticipate that the oil price will ultimately recover. So why not store it in the ground, as opposed to just keep on drilling at this stage? And I've got a follow-up, please.

Okay, yes, I'll address that one, Doug. First of all, we feel very confident that, as Lance has already stated, that we have already captured significant cost savings. So we're not sitting here waiting to capture cost savings. We've already got cost savings in the bank, essentially back through the January timeframe. We feel very comfortable that we are already on that path of capturing cost reduction.

We also continue, of course, to improve the overall productivity of the wells. And when you look at the returns that we're able to generate, we feel very confident that the shareholder is benefiting from those investments.

I will say, though, that we are optimizing our completion program, though. We're not simply just driving forward with our backlog of inventory. As Lance mentioned, we're going to be very judicious about pacing our completion activity in 2015 to ensure that we, one, capture full cost reduction savings at scale. But two, also capture the execution efficiency of running full frac crews.

So my answer would be, we feel very confident in the returns that we're generating. That's a little bit of a bet on the future, in terms of what you see the contango in the future. But we're very comfortable with our investment program.

Okay, I appreciate what's obviously not an easy answer. But in a similar vein, you are quite different from your peers in terms of your dividend, in terms of the scale of the dividend. In this oil price environment, and given -- I guess there's some debate over whether or not you get paid or recognize in your share price with the dividend that you pay. I just wonder if you could help us prioritize your relative expectations for how you allocate cash. And maybe perhaps the level of cash burn that you anticipate in your current budget, including the dividend spend. And I'll leave it at that. Thanks.

Okay, let me maybe address the dividend question, and perhaps I'll ask J.R. to comment a little bit on cash flows and outspend, because I know that's a topic of interest. We are committed to our dividend. When we talk about how we allocate capital, we look at the buckets to which we allocate capital. Our financial obligations, which in our view, include the dividend, are at the top of that list. And we've always said that we'll scale any movement in the dividend according to the health of the business.

But I want to be very clear that we remain committed to our dividends. It's the way that we return value to our shareholders. It needs to be looked at in the full context of the dividend, plus the organic growth that we're generating in our business. With that, maybe I'll just ask J.R. to comment a bit on cash flows and our view of outspend moving forward.

Yes, thanks, Lee. Doug, good to hear from you this morning. I think Lee's indicated earlier today, I mean, we really did design the capital budget to reflect the spend that we believe is appropriate, even in the current environment.

It was really approached quite carefully to balance between this ongoing capital investment in what we believe are attractive returns in our US unconventional resources. And high returns, quite candidly, with our ability and our commitment to continue to maintain appropriate financial flexibility during this timeframe. I think also, let's keep in mind, I am sitting on nearly $5 billion of liquidity today. And I think that puts us in a good position as we start into 2015.

But honestly, that said, we're going to continue to monitor our level of cash flows, based on not only the current price environment, but the expectations in the later part of 2015 and 2016. And look at our cash flow profile accordingly to make sure that we're maintaining that flexibility. And if conditions change, we've got a great deal of flexibility to either decrease, if they get worse, or equally important, to increase if we see a strengthening environment, our cap level of capital spend to really match that increase in cash flows as well.

And then finally, I'd say, Doug, I think Lee highlighted pretty well that we're going to continue to address those matters that are really within our control of the business, operating costs, G&A, and those sorts of matters. So at this point in time, there is no doubt that we are investing a significant portion of our Norway proceeds this year. But we think we're investing them in an organic program that's delivering solid returns for our shareholders.

All right, guys, thanks very much indeed.

Thanks, Doug.

Ryan Todd, Deutsche Bank.

Thanks, good morning, gentlemen. If I could follow up a little bit on that last point, you're maintaining an attractive level of momentum, operationally. And you'll still have on the balance sheet lots of dry powder at year-end 2015. If you think about that cash management going forward, what would you need to see to put money and rigs back to work? Is it a certain level on the oil price? Is it a cash flow relative to a spending outlook? Is it securing a level of cost reduction? What puts money and rigs back to work?

I think, Ryan, that the answer to that is probably a bit multi-dimensional. First it starts with seeing, I think, a sustained recovery in pricing, one with certainly less volatility, that also yields us enhanced cash flows that we can redeploy into the business. Again, we've stated we're not opportunity constrained. That's obvious from our single-well economics in our inventory. So as that incremental cash flow becomes available, we would certainly be looking to invest more.

And in our current plans, again, we're not just looking at 2015. We are looking at 2016 and beyond. And in 2016, we are assuming a moderate recovery in pricing that we think will support some uplift in activity going forward. And we're well prepared to do that. We have the execution capacity to gear up or down in the resource plays quite readily.

Great, thanks. And then one other on the opportunity set going forward. In recent years, you've been a large seller of assets, with the exception of building a bit of position in the SCOOP and STACK area. When you think about that going forward, do you see yourselves more likely still trying to rationalize the portfolio a little bit? Or would you look to be more opportunistic in deploying your balance sheet going forward?

Yes, well, let me first, Ryan, address the portfolio management question. Portfolio management for us is an evergreen process. It's just part of what a healthy E&P company does. We're going to continually test our asset set to ensure that it competes for capital allocation within our portfolio. So you're going to see portfolio management feature in our business model going forward in time.

Now, let's be honest. It's a tough market right now to go out and dispose of an asset and capture true value for the shareholder. But we're going to continue to test the market when we think that it makes sense for the shareholder.

Back on your other question, though, more along the lines of the M&A, the acquisitive side. I would characterize it -- though it's not a focus for us today -- I mean, when you think about the bid-ask spread that's still out there, there's probably still a bit of a gap. But anything that we would evaluate has to compete against our already very strong organic inventory. It would have to come in and compete for capital allocation, which in our view, is a relatively high bar, from a quality and scale standpoint. So that would be, I think, the limiting factor to us, is really finding that quality of asset.

Great, thanks.

Thank you, Ryan.

John Herrlin, Societe Generale.

Yes, hi. Three unrelated ones. With the cost savings, is it just discount from book or changes in procurement, as well as efficiencies and well designs, things like that?

John, it's actually a number of things, all of which you included, and more. There is efficiency savings in there, we realized over the last quarter, that were reflecting in those updated, single-well metrics tables. We certainly have gone out and renegotiated our contracts, in some cases taken on new contracts or negotiated new pricing within existing structures, reflecting the market. And taking every means necessary in that.

I think we look at that, and I'd say we look at the context of those single-well metrics on slide 13, we feel confident. We're confident enough in those savings that we've already reflected new cost-per-well in those tables. And we think that's the beginning or the minimum for this year, and we anticipate additional savings. It isn't clear what the ultimate savings will be throughout the year. We think it's more than we've already achieved. But we wanted to achieve those early in the cycle so we could continue to invest with confidence, and we are. And I also think those well costs we're reflecting are very competitive in each of those basins.

I agree. I just thought you might get more cost savings going forward. Next question for me is on the stack and frac. From the time you spud your initial well to the time you complete the formations, about how long is that in duration?

John, it depends on how big the pad size is. So it can vary from as little as 90 days, could be 120 days. In this case, the stack and frac is going to have four zones vertically, two in the Lower Eagle Ford, one of the Upper Eagle Ford, and then the Austin Chalk. Generally those pilots may even be larger than that, maybe seven or eight wells, as we expand that horizontally. But it's that same vertical stacking. So it's diverse and timed depending on how many are on the pad, quite frankly.

Okay, that's fine. Last one for me is on Oklahoma. Any acreage retention issues at all?

No, I think we're quite confident. We have 70% of our total acreage HBP today, John. And then reflecting those lease expires over the next several years, not just this year, we can maintain those leases with about two rigs, moving forward. Ideally, we'd like to see in a commodity-price recovery, more activity, so we can test other things. But we're confident we can retain all of the value of that lease position within the business plan we presented.

Great, thank you.

Thanks, John.

Guy Baber, Simmons & Company.

Good morning, gentlemen, thanks for taking my question. I had a follow-up on the comment that the unconventional production is expected to rise, exit rate 2015 versus exit rate 2014, which is different than what we've heard from others in the industry who are cutting capital to a similar degree. So I was just hoping to better understand a little bit more specifically how you think you're driving that? And if there's anything that you would point out, maybe differentiated production expectations from one basin to another? Or just if you had any other comments on that front. And then I have a follow-up, as well.

Yes, sure, Guy. I'll just talk generically a bit about the resource plays. I think the reason that, again, we're able to be very capital efficient in 2015 is, again, severalfold. One, we've had the ability to high-grade our inventory, even within our extremely strong core areas. So you've got a high-grading effect where you are bringing the best opportunities forward, not only with a basin, but across all three basins. Secondly, we're able to do that at lower cost for the reasons that Lance has already enumerated. We've captured those early cost savings very early in the cycle, and certainly we're chasing even more throughout the year.

And then as the asset teams continue to drive things like enhanced completion performance, as well as some of the co-development work, the down-spacing work, all of those are tending to improve the overall productivity of the wells also. So it's lifting all boats, if I could put it that way. When you consider all those factors, I think it positions us very, very strongly to continue to drive that kind of exit rate-to-exit rate growth.

Now again, we are still benefiting from some pretty strong carry-in affects from 2014, as well. But as we look across the year and optimize our completion program, we're going to be able to, again, keep that production relatively steady throughout the year with, again, a little bit of uptick in the exit rates for 2015.

Thanks, that's helpful. And then my follow-up was on exploration. You made obviously very significant cuts to the capital allocated there. I was hoping to get some strategic commentary on that front. Does that reflect a permanent shift in the exploration strategy going forward? Or is it more of a specific adjustment you're making this year to better balance cash flow? Just trying to better understand whether for exploration we creep back towards $500 million a year to $600 million a year. Just wanted to get the latest thoughts on how that has evolved as you tested out some of the new acreage you've been building up over the last few years.

Great question. Exploration remains attractive to us for obvious reasons, because of the strong multiples that it can generate, again, when we're successful at exploration. To be very frank, we are not satisfied with our historical performance in exploration. And under Mitch's leadership, we feel a need to improve in that area.

And while we're searching for the enhanced approach that will drive those improved results, we are reducing spend materially. A lot of that reduction, quite frankly, was in place on an activity basis before the commodity price correction, though. So it was largely driven by, I would say, scheduling and commitments that we had in the 2015 time period.

I would end just by saying that exploration must compete for capital allocation, like every other aspect of our business. And so this year, yes, the spend will be materially reduced. And as we look forward in time, opportunities in exploration will have to go head-to-head with the other investment opportunities we have in our portfolio.

Thanks for the comments.

Thank you.

Jeoffrey Lambujon, Tudor, Pickering, Holt.

Good morning, thanks for taking my questions. Just in trying to think about future potential cost savings, on the $225 million factored in so far, is there a breakout you have in terms of North America versus international? If it's primarily US resource plays, imply closer to 8% to 9% in cost savings. Is that the right way to think about it, or is it more of a balanced split?

That's a great question, Jeoff. I would say that $225 million is specific to North America, and really specific to the three resource plays underneath it. So it's built into the development costs we've already captured to date, primarily in Oklahoma, Bakken and Eagle Ford. I think the way you're describing is accurate it's on that. And that's our minimum floor. We expect that to grow materially over the balance of the year.

Jeoffrey, this is Mitch Little. I'll just add a little bit to that from the international and offshore side. We are seeing some modest reductions across a number of suppliers. We've got specific plans in place at each asset. But keep in mind that a lot of the projects we're executing in that space are long cycle, prior commitments, executed long-cycle contracts, which aren't going to be subject to the same volatility as we are seeing in the North America and onshore business.

Okay, great. And then last question for me. In regards to ongoing optimization on completions, how do you view that pilot testing going forward for increased prop and loading, additional completion changes, just given lower commodity prices, and the incremental capital required up front there?

I think you'll see us continue, Jeoff, with completions optimizations on an ongoing basis, effectively indefinitely. We're always going to look for that better well productivity at the lowest cost possible, particularly as we look at Bakken and Oklahoma, where we have lower activity for the year. We see this is a great opportunity to drive well productivity, as well as test spacing, so that as prices do recover in the future, we're very well positioned to grow to full-field development scale quickly, and at the highest value for the Company.

I think we're confident we'll continue to see improvements on that. Working in all three of those basins and any new basins in the future on optimization is just going to be a natural cycle of our business.

Thank you.

Thanks, Jeoffrey.

Pavel Molchanov, Raymond James.

Thanks for taking the question. You've always talked about share buyback as a flex variable. And I suppose now that you've cut CapEx by 40%, if oil prices were to recover, what's going to be the decision variables between allocating increased CapEx versus perhaps resuming buyback?

Yes, Pavel, this is J.R. I think that's a fair question. We've talked a lot about how share buybacks have got to compete against organic capital re-investments. I think we demonstrated that in 2014.

You'll recall back when we sold Angola, the thought process was, what was that next best highest use of capital? And at that point in time, it's is a little bit of history, we had just significantly ramped up activity across North America. And at that point in time, we were not ready to make that next incremental investment in North America, given our desire to see us operating at that higher scale. So really the next highest and best use, from an allocation standpoint, was share repurchases.

Now fast forward. Not only do we find ourselves in this volatile commodity price environment, but we find ourselves with a level of capital spend that really isn't funding a large portion of our organic investment opportunities that are still higher earning. So it is a much different conversation regarding what is the risk-adjusted return of that organic re-investment versus the share repurchases.

But I've got to tell you though, Pavel, until we see a bit more clarity around the depth and duration of the commodity price correction that we're in right now, I feel like the balance sheet is probably the best place for any incremental capital at this point in time, until we see a strengthening of the cash flows. But again, at the appropriate time, share repurchases is going to be a consideration for capital allocation. It's just going to have to continue to compete on a risk-adjusted basis.

Okay. And then just a small housekeeping item about the production guidance. Are you giving credit to any volumes this year from your first development in Kurdistan?

Yes, as I mentioned in my comments, we are currently forecasting first production from the Atrush, non-operated Phase 1 block late this year. We also have very small production from the Sarsang block, which is about 4,000 gross barrels of oil a day.

Very small. Very small number.

Okay, understood. Thanks very much.

Thanks, Pavel.

Jason Gammel, Jefferies.

Thanks very much. I just wanted come back to J.R.'s comment about the balance sheet. Do you have any -- as you think about capital allocations upper limits on, let's say, a leverage ratio, that you would be willing to go to if we have continued low prices? Net debt-to-cap ratio -- something along those lines?

Yes, Jason, I think that's a fair question. One that I've always tried to maintain the most flexibility, and not necessarily commit myself to a ceiling. But that said, first and foremost, I want to make sure it's clear that we are committed to maintaining that strong balance sheet. And we'll continue to keep that commitment throughout this commodity price cycle. I think I said earlier -- or at least today -- at year end, we've got nearly $5 billion of liquidity, $2.4 billion of that in cash.

The way I look at our investment-grade rating, and I think it's a solid investment-grade rating is it does reflect one that we would expect to maintain throughout this commodity-price cycle. And I think the rating agencies have always historically rated our sector based on a through-the-commodity, price-cycle approach, and not just in the environment that they're in.

And finally I'd say, I think as we've done that, Jason, we've taken that into consideration in designing the 2015 capital program, it does reflect that balance between the need to continue the ongoing investment at high returns, while at the same time maintaining that balance sheet. That said, and I think I mentioned it earlier, we're going to continue to watch the current environment and ensure that our capital profile and our operating cash flow profile are appropriately taken into consideration, depending on that environment.

Got it, thanks. That's helpful, actually. One more if I could, please. And I apologize if this has been in the weeds. But this is the first time I've really seen the data on the Austin Chalk type curves. Trying to understand how it's giving a better IRR than an Eagle Ford condensate well, given that the IP is lower, the EUR is lower, and the completed well cost is higher, but it's about the same level of liquids production?

Sure, Jason, great question. I would encourage everybody to think that the IP of a Lower Eagle Ford well and an Austin Chalk well are similar, with the Lower Eagle Ford being a little bit better. But what really happens is, really by the third month, those two have equalized, and then the Austin Chalk well declines at a little bit slower rate. So when you look towards, say, a 180-day cumulative production, the Austin Chalk is just higher than the Lower Eagle Ford well. And it's that early-life production, particularly the first and second year, that drive the value by bringing forward the cash flows from those extra barrels.

Okay, perfect, that's real helpful.

And as a result, you see those attractive return metrics for the Eagle Ford.

Yes, Jason, I think you also highlighted something that I think is important. This is the first time, as Lance said in his prepared remarks, that we've actually shown standalone, single-well economics for the Austin Chalk. So I appreciate you pointing that out on the call.

Would you be able to share what the first-year decline is on the Austin Chalk relative to the Eagle Ford condensate?

Jason, I don't know that I actually scrutinize them in that detail. I think the Eagle Ford range is depending on type curve from 70% to 78%. And it's just a few percent lower. But those incremental barrels make a difference in the Austin Chalk.

I do think I'd like to reiterate. We said several times before, we could only afford to co-develop Austin Chalk if it would compete favorably with economics. So we're quite pleased to be able to show these and demonstrate that co-developing those horizons is the right choice today, because they have very favorable returns together.

Got it. Thanks for the comments, guys.

Thanks, Jason.

Jeffrey Campbell, Tuohy Brothers.

Good morning.

Good morning.

I'd like to go back to the cost reductions and just ask a little bit different question. One concern that I think people are talking about is that when oil prices recover, D&C costs are going to rise again as well. So I'm wondering, how sticky can margin enhancement based on cost reduction remain?

You know, Jeff, it's a good question. I think first and foremost, in the current market, our focus is with margins compressed by lower commodity prices, it's incumbent upon us to be aggressive in pushing those service costs and tangible good costs down, so that we protect our margins and our short-cycle investments as early as possible. I hope we've demonstrated that we're doing that. And it will be up to us to do it. I think even as commodity prices rise, you will see pressure on those. We will obviously work to defend those to the extent we can, and push on that.

It's not all just cost savings, though. We continue to focus on cycle time reductions and efficiencies. So the efficiencies we can achieve in a market, those will be very sticky and stay with us in a perpetuity basis. Obviously just like commodity pricing, we will have, to some extent, less control over service costs.

Jeffrey, I would just add, too, we have to look at those elements of our cost structure too that will be durable irrespective of where the pricing environment. I mentioned a few of the things that we can pursue. And we're looking at every means available to us.

An obvious one for us is with our response to the commodity prices and the commensurate, I would say, reduction in activity, we're taking, of course, a hard look at our organizational capacity. And of course on that front, we're in the midst of implementing a reduction in organizational capacity that's going to take some 350 to 400 positions out of our cost structure going forward. So I want to make it very clear that we're doing the things necessary to put in place cost-reduction initiatives that will be durable throughout the cycle.

Got it. That's very helpful, thank you. Some of your peers say that the Springer Shale produces the best returns in the Oklahoma resource plays. You have a lot of non-op data, but you appear to be moving into operated Springer drilling at a deliberate pace. I'm just wondering what your forward view is on the Springer? And that can be both 2015 and beyond.

Jeff, we also see the Springer as potentially very valuable. It may be among the most valuable investments we could make in Oklahoma. We have planned to be more active, quite frankly, in 2015, in the Springer, to test it earlier.

As we've gone through the cycle and looked at what our prudent activity is, we've reduced our forecast activity in Oklahoma. And as a result, and our need to make sure we're maintaining our very valuable SCOOP and STACK leases in the area, we found it necessary to start our own operated Springer activity later in the year than possible. That does not reflect a lack of confidence on our part. It really reflects some constraints on the amount of activity we'll have in Oklahoma during the year.

By way of having a diverse and large portfolio, particularly in the SCOOP area, which is overlain by the Springer, we've had the benefit of participating in, I think, nearly three quarters of all Springer wells drilled to date. So we do have a lot of data, and we're advancing our understanding of the reservoir performance early. But of course, we're excited to get to our own operated activity later this year.

Okay, great, thanks. If I could ask just one last quick one. Where are the current and future Upper Eagle Ford locations relative to Lower Eagle Ford and the Austin Chalk? And really what I'm thinking of is the slide 5 that talks about the stack and the frac.

Right now, we're early in the Upper Eagle Ford and the stack and frac, really bringing on our first pilot group to the Upper Eagle Ford. And so, I'd start with that group. We have some places where we've delineated Austin Chalk. And in some of those areas, we recognize that the reservoir quality in the Upper Eagle Ford may actually be superior to the Austin Chalk. So we may develop the Upper Eagle Ford and the Lower Eagle Ford together. We're testing that now. It will be some time before we understand the delineated area.

And then on the stack and frac, we have some areas within our acreage where we see a very prospective Austin Chalk, Upper Eagle Ford and Lower Eagle Ford. And that's about us testing all three of those together. In some cases, we'll actually have two wells in the Lower Eagle Ford, like this first pilot. Again, with that first one drilling and not on completions, I think we have an idea of where that performance is. But it's early days, and we just need to see that performance before we can talk about how delineated it can be.

That was so very helpful. Thanks, I appreciate it.

Thanks, Jeff.

And I'm not showing any further questions at this time. I will now turn the call back over to Mr. Zack Daley.

Thanks. I'd like to thank everyone again for their participation this morning. Please contact me if you have any additional follow-up questions. In conclusion, Marathon Oil is well prepared for the current low-price environment, with a 2015 capital program focused on our highest return in investment opportunities and prudent management of cash flows. Combined with maintaining financial flexibility, we're positioning the Company to be a stronger E&P in the future. This concludes today's call.

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