馬拉松石油 (MRO) 2014 Q2 法說會逐字稿

Welcome to the Marathon Oil Corporation 2014 second-quarter earnings conference call. My name is Ellen and I will 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 Chris Phillips, Director of Investor Relations. Mr. Phillips, you may begin.

Good morning, and welcome to Marathon Oil Corporation's second-quarter 2014 earnings call. I'm Chris Phillips, Director of Investor Relations. Also on the call this morning are Lee Tillman, CEO and President; and JR Sult, EVP and CFO.

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. Our comments and answers to questions will contain forward-looking information subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. I refer you back to the aforementioned slides, where you can find our full Safe Harbor statement.

With that, I will turn the call over to Lee.

Thank you, Chris. Let me add my welcome to Marathon Oil's second-quarter 2014 earnings conference call. Before opening the lines for Q&A, I'd like to take a few minutes just to share a few personal thoughts.

Last week was a bit of a special week for me. This past Friday, August 1, marked my first full year as President and CEO at Marathon Oil. It's been a remarkable year of growth and positive change for our Company. I'm very proud of what we've accomplished in this first year.

We outlined a comprehensive strategic framework, what we call our seven strategic imperatives, as well as three tactical priorities for 2014 back at our Analyst Day in December. And we've made great strides in advancing against these commitments toward our stated goal of becoming the premier independent E&P company.

We've accelerated activity across all three of our high-quality US resource plays, underpinned by a growing unconventional resource base. We've executed strategic divestitures in Angola and Norway to both simplify and concentrate our portfolio. And finally, we've delivered direct value to our shareholders through material share repurchases and a competitive dividend.

I believe our Company is fundamentally stronger today than it was 12 months ago. And I give full credit to the leadership team and our dedicated employees for embracing the changes to our portfolio and to our organization. But, I also want to a knowledge that there is much left to accomplish if we are to be recognized as a premier independent E&P company.

Many of you know that I have a passion -- in fact, my wife might say obsession -- for cars and racing. So, let me put it to you in racing terms. We have our car well set up. We've run our qualifying laps. We even got ourselves a spot on the grid, but the race is just starting. And it's time for Marathon Oil to shift to the next gear.

Our seven strategic imperatives drive our business strategy, and they have gained great momentum across our organization as we continue to make the shift to become a competitive independent E&P. We must continue this shift to align our strategic commitment to rigorous portfolio management, capital discipline and shareholder value.

We are fundamentally striving for an organization that remains true to its core values to protect its license to operate, but that also has a bias toward action, a commitment to stewardship, that is guided by sound risk management, prolific opportunity generation, efficiency and scalability in our processes, rigorous external benchmarking and a rapid sharing of best practices. A challenging and innovative culture where performance is not only differentiated, but also rewarded.

And last, but not least, a culture that creates a great place to work for our motivated employees. I am personally asking our employees to test each and every decision against our seven strategic imperatives to ensure alignment and to make sure that we drive shareholder value in all their daily work activities.

We understand that you, our investors, have options, that you are choices. And it is our responsibility to make that compelling investment case for Marathon Oil. We must deliver consistent, predictable financial and operating results quarter on quarter and year on year, with a clear focus on long-term value creation. We must be good stewards of our shareholders' trust and our shareholders' capital.

For our investors and the analysts covering our Company, thank you for your support and continued confidence in Marathon Oil during my initial year. And rest assured, this leadership team listens to your feedback as we strive to profitably grow our Company and create long-term value.

With that, let's turn our attention to the second-quarter results and open up the call for your questions.

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

(Operator Instructions)

Ed Westlake, Credit Suisse.

Yes. Good morning, and congratulations on the progress, particularly in the US. You flagged in a RISA, a 25% increase in 180-day cumes for some of the Eagle Ford wells with the new completion. I'm just wondering what change you're seeing and if you could update us on the EURs, particularly for the condensate window, but also for the oil window.

Yes. Good morning, Ed. Thanks for the question.

We're very pleased with the completion performance that we're seeing in the Eagle Ford. As you quoted, we have a population of wells with 180 day cumes that are really generating, on average, 25% relative to our model type curve.

The bulk of that improvement is, of course, being driven by optimization of our completion designs, a lot of that having to do with dropping our stage spacing down to 250 feet and below. Our expectation is, as we get a bit more data, we intend to update -- do a comprehensive update on the type curves a bit later in the year, and at that time we'll provide some updated EURs, as well.

Okay. And then just a separate follow-on, just on the SCOOP. Obviously, you're still drilling some good wells and adding acreage. Given the cash you've got coming in from Norway, when do you think you might accelerate your development in the SCOOP, and how would that fit into maybe acceleration elsewhere in the portfolio?

Right. Maybe I'll just take the general question around -- as we move toward close in the fourth quarter around our Norway transaction, of course a key question of our investors is how we intend to redeploy those proceeds. We've stated explicitly in the press release that, of course, the first call on that those proceeds will be around organic reinvestment.

And the confidence that we have in that organic reinvestment is really underpinned by what we've seen in our downspacing and completion optimization in both the Eagle Ford and the Bakken, the continued expansion and delineation of our acreage footprint in Oklahoma. As we move into our business planning process in the second part of the year, we fully expect that a further acceleration case -- and across really all of our resource plays -- will be a key consideration in that dialogue.

Okay. Thanks very much.

Thank you, Ed.

Ryan Todd, Deutsche Bank.

Hi. Good morning, gentlemen. If I could talk a little bit more about the acceleration that you've referenced. At this point, what more do you need to see in the Bakken and the Oklahoma to accelerate activity? Is it still waiting on results of pilot tests, or delineation work, or what more do you need to see at this point to deploy the cash?

Yes. Well, it's continued well performance, and also, of course, getting those results from those comprehensive pilots. As you look around the three resource plays and the Eagle Ford, as we announced in the press release, we've continued to delineate our position in the Austin Chalk upper Eagle Ford, which, of course, provides some potential uplift in our total resource base.

When you look at the Bakken, greater than 50% of the completions that we are pursuing in the second half of the year are explicitly testing enhanced completion designs. In addition to that, in the Bakken we're looking at moving aggressively from our four wells per DSU up to six wells, using basically a six by six per DSU between the middle Bakken and the Three Forks. And because of the nature of that pad drilling, much of those results would not be available until late 2014, early 2015.

And then, of course, in Oklahoma we're continuing to not only ensure that we protect our leasehold there in our high-quality SCOOP acreage, but as we work around, we're delineating the southern Mississippi trend, as well as our Granite Wash opportunity. So, there's a lot of activity that is going to ultimately culminate in that decision to further accelerate across our plays, and that will be part and parcel of the business planning process that we're going through currently.

In the Bakken in particular, to potentially -- to use your racing terminology, to put your foot on the gas more? Is it going to be dependent at this point on pilot plant and completion testing, or is that still -- can you accelerate in the meantime?

Yes. We're going to move aggressively in the Bakken. When you look at our quality and materiality of our acreage position in the Bakken across our three core areas -- Hector, Myrmidon and Ajax -- we see a compelling opportunity there; hence, the uptick in our activity in the second half of the year. That provides us a very strong foundation should we move toward a more -- a higher acceleration case in the Bakken.

Great. If I could ask one on a different strategic, a higher strategic level. You've done a lot over the past 24 months in terms of narrowing your international portfolio and narrowing your focus as a Company.

And if you look at the international exploration program, you're still fairly diverse in terms of taking shots around the globe. Can you talk a little bit it about where the international exploration program fits into the broader portfolio and the newer, narrower focus of Marathon as an onshore-focused company?

Absolutely. We view that the exploration portfolio has to compete for capital, not unlike the rest of the assets in our portfolio. In terms of narrowing the focus, we feel that we have, in fact, narrowed the focus really into four key areas, which are East Africa, Gabon, Kurdistan, as well as the Gulf of Mexico.

And as we get results in those areas, we'll continue to test those assets in the exploration portfolio as to how best to monetize. Is it best for us to develop, or is it best to look for another way to generate value for the shareholders?

Just like all of our portfolio, we continue to test our exploration assets, as well, to see what they're yielding in terms of results and how those may be accretive to our shareholder. But, we're going to continue to keep the exploration program very focused -- very much focused on oil-prone emerging plays, where we can come in and add value as the operator.

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

Thank you, Ryan.

Paul Sankey Wolfe Research.

Good morning Lee, Chris.

Hey, Paul.

The previous question has been driving towards the potential for acceleration. I guess that you are outperforming your targets to an extent. Could you just remind us what your key targets are for the Company, the ones you want us to focus on in terms of volume growth, obviously, by play, to the extent you're prepared to talk about that?

It's just -- I'm looking at your slides and I see some guidance for 2014, but could you talk about, not only 2014, but also beyond and what we should think of you as capable of achieving? Thanks.

Well, certainly for 2014, Paul, we are very committed to our greater-than-30% growth across the resource plays, and that's fully consistent with our full-year guidance. And maybe I'll pause for a moment, because I know this quarter is -- I'll acknowledge, is a little bit messy, because of the movement of Norway into discontinued operations, and hence, the reason we've recast, of course, not only third-quarter guidance, but full-year guidance to reflect the continuing operations element of our business. But that new guidance fully reflects that greater-than-30% growth in our unconventional resource plays.

Looking ahead, I would say, we want to ensure that our growth targets, which will be developed as part of our business plan, are competitive in the current E&P peer group that we compare ourselves against. Later in the year we'll give a little bit longer runway in terms of where we see those compound annual growth rates going in the future, but I'd like to probably hold that until we get a little bit further along in our business planning process, and also have the full opportunity to evaluate the potential for further acceleration in the US.

Great. Thank you. My second question is, have you applied to export condensate from the Eagle Ford lightly processed up in Washington?

Yes. Let me maybe step back on that one and take the big picture question first, which is, I think I've been pretty vocal in my external comments that Marathon is very much committed to a lifting of the overall crude export ban.

We think putting our unconventional barrels into the world open market is the right answer for both producers, as well as consumers. We want to have our barrels compete in the world open market. Not surprisingly, with that philosophy, we are pursuing every avenue available to us to take advantage of the current regulatory environment to ensure we have the optionality to get our barrels, particularly condensate, out in the market.

I'll also maybe pause on condensate for just a moment. Given that there's not an industry-accepted definition, I would say, for condensate, let me just give you a little bit of color on our Eagle Ford production. Our Eagle Ford production, unlike some of the other operators, is actually quite heavy in terms of API.

Materially, more than 50% of our production in the Eagle Ford is less than 50-degree API. And that mix will vary as we change well mix over the years, but in general, that mix looks pretty solid going forward. We have a pretty heavy barrel in the Eagle Ford, and hence, our C&C, crude and condensate, realizations are largely priced at LLS minus $6.

Having said that, we still want to ensure we have maximum optionality of getting our barrels potentially to other markets with higher realizations. One of the ways that we're achieving that is also making sure that we've maximized our volume on pipe out of the Eagle Ford, and ensuring that we get access to the water at Corpus Christi. That work all continues to move forward.

So, I would say on multiple fronts, we continue to drive toward positioning ourselves to be ready to take our condensate into the open market.

Great. I guess that's the long way of saying that you have applied to export?

I'll let you make your interpretation, Paul.

Thanks a lot, Lee.

Great question. Thank you Paul.

Doug Leggate, Bank of America.

Thanks. Good morning, Lee. Good morning, everybody.

Hi, Doug.

I have two also, if I may. Lee, if I could go to the Bakken, please. I'm a little curious that you are moving, obviously, to 50%, per your commentary, for the enhanced completion design. But you haven't really given as much indication as to what that means in terms of any potential change to your type curve.

So, I wonder if you could just help us help characterize what that enhanced completion then is doing for you in terms of IP rates, type curve, and maybe what the running room is in the play. And I have a follow-up, please.

For us in the Bakken, Doug, there are really two things going on there. One is, the downspacing that we're doing. As we mentioned, we've already spud one of our 12-well spacing pilots for 1280 DSU. So, I think that is an important element of the work that we're doing.

Implicit to those pilots, as well, though, we also are testing these enhanced completion designs, which, as you state, our anticipation is that those are going to have more deliverability that will enhance our overall type curves. But, we need to see the data first.

What I'll share is that when you look at our current -- either 2P or total resource -- that we've externally communicated on the Bakken, that's largely based on a four-well for individual horizon per DSU. So, as we move from six and higher, we would expect that to have an upward vector on our overall resource potential.

Similarly, as we see more efficiency in our completion design, whether that's through stage spacing, through profit loading, through slickwater hybrid fracturing, or even some of the cemented liner completions that we're trying, we think that that will also be additive and be value creation, and at the end of the day, add to the resource base at the Bakken.

My preference is to provide a more comprehensive update on our resource position a bit later in the year, but later in the fall, and we will likely do that, not only for the Bakken, but also for the Eagle Ford, as well as the Oklahoma resource basins. We're still very early, I guess, is the bottom line answer there, Doug, but we do anticipate that those are going to be driving us toward potential resource adds in the future.

Great. I'll wait on the update.

My follow-up is, you obviously tried to sell the UK, and Norway's gone. The growth in North America is, obviously, pretty punchy on an absolute basis when you isolate North America. But, there is a little bit of a [narrow shove in the fat east] over the large position in EG.

I'm just curious, when you look at the things that Apache came out with recently in terms of trying to concentrate the market's attention back in its North American portfolio, I just wonder if you could characterize your appetite, or perhaps your longer-term views, as to whether an international footprint for Marathon is still the right strategy, and EG in particular? And I'll leave it there. Thanks.

Well, certainly, I'll start by saying at a high level, we never view that our portfolio optimization is completed. And, as I've said many times before, Doug, we're going to be driven by profitability, not by geography. As you mentioned, we still have operations in the UK internationally, as well as in Equatorial Guinea. Those operations will continue to be tested in terms of their fit in our portfolio.

We made an attempt to market the UK position and were unable to achieve full value for our shareholders, so we've elected to continue to operate there. EG, a little bit different position in that production, relatively flat, very strong cash flows there. We also, as you're well aware, Doug, have a pretty interesting exploration program kicking off in Equatorial Guinea here in the third quarter, where we're exploring some very interesting oil potential on our current block.

We continue to see the potential for EG to have opportunities that would compete for capital within our broad portfolio. If we get to a point where that's no longer the case, then we'll have a different discussion around, what are the forward prospects for Equatorial Guinea.

All right. Thanks a lot, Lee, for the answers.

Thank you, Doug.

John Herrlin, Societe Generale.

Hi, thanks. Two quick ones for you, Lee. You mentioned in the release and in your current comments and last night's comments about greater completion efficiency. Notionally, with the unconventionals, how much further do you think your spending dollars are going as a consequence of improved well designs and other operational practices?

Well, we continue to be value-driven. Of course, we want to deliver the lowest completed well costs that we can, but we also want to make sure that we're mindful of generating the highest PV, as well.

For instance, if you look at our standard design in a place like the Eagle Ford, we typically have 22 stages of fracs. We typically use about 5 million pounds of proppant, and we're now driving stage spacing to 250 foot. In fact, in many of our completions, we're now testing even going below 250 foot. We're also looking at various fluid loadings, as well, that will influence our ability to drive efficiency there.

The learning curve continues to exist on the completion side across all the US resource plays. The technology continues to move. One of the advantages that Marathon has is that we learn from all three resource plays, because all have very different completion techniques and strategies.

In the Eagle Ford, we have plug and perf, in the Bakken, we're using sliding sleeve, and in the Oklahoma resource basins, we're using slickwater with plug and perf. So, we get to see a lot of different completion designs, and it's really taking the best of those and applying them for the region of interest to generate the most returns.

In terms of the true return on that incremental investment -- and I'll use the example of maybe stage spacing in the Eagle Ford -- there is a cost to dropping down to more stages -- more frac stages per well -- as you drop that stage spacing to 250 feet and below. And we have tested that against the incremental value that it generates, and absolutely see the return there for those incremental dollars.

Okay. Great. Next one is a follow-up on some of the other questions.

If you look at your asset base, and you can either put on your VSRA hat or SCA hat, or NHRA hat as a driver, when you look at it, in terms of the spending commitment, you said earlier that everything is rated, whether it's exploration or unconventional -- or conventional versus unconventional. On a going-forward basis, how would you lay out your spending, conventional versus unconventional? Obviously, you have commitments on the development side, but in terms of seeking new resources?

Yes. Well, as we talk about overall capital, just to maybe review where we stand in 2014, about 60% of our capital is largely directed toward the US resource plays. And as certainly as we look forward into the near-term, particularly 2015, we still continue to see a strong case for those US resource plays competing very well for capital allocation.

Now, that excludes any potential discovery in the exploration space, or, for instance, even in the previously referenced EG exploration program, which could change the dynamics there. We've often talked about wanting to exercise the discipline of keeping our CapEx within our operating cash flow, but we don't view that as a limiter. We view that as good discipline. But certainly, if we see great opportunities, we're willing to step outside of our operating cash flows to pursue those.

Great. Thank you.

Thank you very much.

Guy Baber, Simmons.

Good morning, everybody, and thanks for taking my question. I want to go back to the Bakken for a minute, with more of a backward-looking question, I guess, for me. But despite some weather complications earlier in the year, you appear to be easily tracking ahead of the full-year guidance that you would have given at last September's Analyst Day.

So, was just hoping you could maybe shed a bit more light as to where, specifically, you're outperforming relative to the internal plan? And maybe what has surprised you internally? Is it maybe -- is it better well results, more efficiencies? Just any more color there would be great.

Yes, absolutely. We have made a strong recovery in the Bakken, post the weather impacts in the first quarter that ourselves and many other operators experienced. But, we are now tracking very well relative to our plan. In fact, we feel that we'll be able to accommodate the various completion enhancement tests that we want to do in the second half of the year within our capital budget.

We're being very efficient in the Bakken. We're seeing very strong results, not only from our drilling program, but even our re-frack program that we're executing this year with a dedicated re-frack rig is also delivering very strong results. And, we're about to move from the higher productivity areas of the Myrmidon to test those re-fracks also as we move into the Hector area.

We've had some very good results. We've had very positive results from the early four-by-four spacing pilots that we've implemented in the middle Bakken and the Three Forks, and that has, in fact, given us great confidence to move forward in the second half of the year with the six-by-six format of the 12 wells per DSU going forward. The results continue to be very positive in the Bakken.

Okay, great. That's helpful.

And then my follow-up was, as we begin to think about the potential and possibilities around you allocating more capital to your unconventional plays, both in total, and then from one play to the next, can you just highlight for us any constraints or limits we might need to consider with respect to you all quickly ramping up investment in each of your primary plays? Are you maybe more constrained in certain areas than in others? Anything from an infrastructure perspective, or people perspective, or anything else that you might highlight?

Yes. Good question, Guy. As we think about acceleration, and like I said, looking toward the end of this year, what actions we might have to take if an acceleration case proves beneficial. We have high confidence in our execution model in all three resource plays.

It shouldn't be surprising that we've already tested our ability to step up in terms of the ability of the service industry, whether that be frack crews or rigs, to support a further step-up in activity. It's a similar process that we went through last year, as we tested our ability to make the first step in acceleration.

It would just be building on that. We don't see any constraints today, either from the service sector or from a rig standpoint, and certainly not from an internal support standpoint, that would preclude us from taking another step in terms of acceleration.

Thanks very much.

Jason Gammel, Jefferies.

Thanks very much. Just wanted to talk about the pace of bringing wells to sales in the Eagle Ford. I know first quarter was a bit of a slip because of several issues, but can you talk about how many wells that you still have an inventory that need to be brought on to sales, and whether we should think about the pace moving forward as essentially same number of wells being drilled being brought into sales?

Jason, the second quarter was much more indicative of our ability to deliver wells to sales. As you mentioned, the first quarter was a bit of an anomaly as we brought new rigs into the fleet. We were also making some changes to our well designs, et cetera, that was creating a little bit more measured depth on some of our wells. All of those contributed to driving some of our performance in the first quarter.

The intensity, also, of our pad drilling, as you're well aware, changed in the first quarter. We averaged about four wells per pad in the first quarter. That number has gone up to about 4, 4.5 -- 4.4, 4.5 now in the second quarter.

But, we feel very confident now that we're generating the inventory that will keep our five frac fleets very well loaded. Our current inventory -- and again, this is just a ballpark number, Jason -- is probably about five pads, or 30 wells, that we currently have in inventory.

Okay. Great. Then if I could just turn to the SCOOP play. I'm afraid I'm still learning about this one. Can you talk a little bit about the potential running room that you have there in terms of an inventory?

And then also, obviously, the extended reach lateral had the pretty impressive flow rate. Can you talk about the amount of irrigates that is contiguous that would support these extended reach laterals?

Yes. Well, certainly, for us, we're very bullish on Oklahoma. We've continued to grow and consolidate our acreage position there, as we noted in the press release. With further delineation, with some acquisitions and some greenfield leasing, we've moved our acreage position now to over 300,000 net acres.

About 80% of that is in the SCOOP and STACK areas. So, we have a very deep inventory in both SCOOP and STACK, as we look forward. Again, I would say our intent is to provide a bit more of a comprehensive update on the resources associated with that acreage position a bit later in the year.

But, to your specific question around SCOOP XL, we've had very good success with the SCOOP XL. They're delivering outstanding incremental well economics, would compete very favorably for capital. Part of our consolidation and growth in Oklahoma is focused on ensuring we can maximize the inventory of XL wells that we can access. Because, of course, it has a lot to do with lease configuration, as well as the specific geology that you find in an individual lease. But

But, we absolutely want to maximize our exposure to SCOOP XL wells. It's not that the SCOOP wells are poor performers. Our SCOOP wells are still delivering 1300 oil equivalent barrels per day relative to, say, the 2000 that you might see in the SCOOP XL wells. But we know when we can deliver the XL design, that's exactly where we want to hit.

Okay, great. Could you maybe mention any uplift that you got in the IRR of the XL wells versus the standard SCOOP wells?

We've shown some incremental well economics in our last external. But certainly, you're getting significant uplift in terms of return on the XL wells, particularly when you consider the 2000 oil equivalent barrel-per-day 30-day IPs.

Okay. Thanks very much.

I think the IRRs, Jason, run north of 50% on those SCOOP XL wells.

Great. Thanks very much.

Roger Read, Wells Fargo.

Hi. Good morning.

Good morning, Roger.

Just to come back to the Eagle Ford a little bit, and I recognize we'll have more information later this year. But, can you give us an idea, as you look at the enhanced completions of the Eagle Ford there, the improvement of the 25% against the type curves, but what are you seeing in terms of additional costs? Hopefully, a lot less than the 25%. But I just hoping to get maybe an idea of the extra cost per well, and then whether or not you're seeing any -- or whether or not any service cost inflation is included in that, or if that's a relatively static event at this point.

Well, certainly our current well costs in the Eagle Ford is running around, from a completed-well-cost standpoint, around $7.4 million. And that, of course, incorporates moving to the reduced stage spacing that we've previously referenced. Certainly, the reduced stage spacing, though, Roger, does put upward pressure on the target costs of our wells.

However, to your second question around service company costs, what we saw at the beginning of 2014 was actually some cost savings in the service sector, particularly on the pumping side, as well as some of our intangible costs on OCTG. We have had some other offsets as we've intensified the density of our frac stages. We've also been able to find some offsets, as well.

But there is, in all honesty, some upward pressure there. When you just look at the -- I'll call it the gross cost of stepping up the stage density -- you're probably talking about $700,000 gross per well. So, you're having to accommodate that level of cost in your target well cost. But, that $700,000, again, is very well justified in terms of the incremental return that you're generating.

Right. Well, that's what I wanted to see. Thanks for that.

And then on the second and completely unrelated question, Kurdistan. Obviously, that area is in the news almost every day, it seems like. I was just wondering, in terms of, as you're looking at your international exploration program, how that's fitting in from a capital allocation standpoint?

And whether or not -- maybe you haven't had many people there, since a lot of it's not your operation. But I was just wondering whether or not you have people there, what you would need to see to put people on the ground in Kurdistan again.

Well, first and foremost, our number one priority is keeping our folks safe and secure. We, of course, just like everyone, have been monitoring the situation in Kurdistan very, very carefully with the developments there in Iraq with ISIS.

What I can share with you is that our operations, as well as the operations in our OBO -- operated by others -- blocks there, to date, have not been impacted by the activities there. The Kurdish regional authority has had a very stabilizing influence. We simply have not seen an impact on our operations. But, we are monitoring it on a day-to-day basis to ensure that our folks are protected from a safety and security standpoint.

In terms of backing away from the security question and maybe moving more to the more geologic side of things and how it competes for capital, we have had very good success in Kurdistan. When you look at our operated block, Harir, we've had the Mirawa-1 discovery. We are currently testing the Jisik-1 well. We've got the Mirawa-2 appraisal well scheduled for later in the year.

So, on the operated block, we feel very strongly that we've had very good geologic success there. We're still, again, early days. We're still doing exploration and appraisal, but it looks quite promising from a geologic standpoint.

Similarly, on our non-operated blocks, we continue to make good progress there. Atrush, of course, is moving rapidly toward first oil next year. That will be a 30,000 barrel early production system in 2015. And then, on our Sarsang block, which is also non-operated, we're currently testing the East Swara Tika-1 well.

A lot of activity there, We're thankful that that has not been impacted by the security issues in Iraq, but we're going to continue to monitor that.

Okay. Thank you.

Thank you, Roger.

David Heikkinen, Heikkinen Energy Advisors.

Good morning, Lee. You've highlighted that you don't see any constraints to accelerate. Can you talk about, as you think about accelerating, what you see on the delta of services and drilling cost basis? And then how you offset that with efficiency? You hit the 700,000 per well increase, but makes better returns. I'm just trying to get into the base cost, apples-to-apples, of what you're saying?

Yes. Again, if I look at the first half of the year, I would say that our service costs were flat to down. There was still good commercial tension there. We also, again, as I mentioned, saw it in some of our tangible goods, as well.

You can sense that there's a bit more of a tightening around availability. When you look at rigs and pumping crews, particularly as the activity continues to be at a very high level -- and there's some rebalancing around the resource plays -- as you see the Permian competing for a lot of the horizontal activity, as well.

As I look out to the second half of the year, I would anticipate that we'll see a little bit of upward pressure on the services side. And we're going to have to continue to work to offset any of that commercial pressure.

Now, I will say, with our scale across all three of the resource plays, we're dealing from a strong position, from a negotiation standpoint, because we do have a very large book of business. The other aspect I would point out, that as we move to longer laterals, more complex turns associated with more pad drilling, we are trying to go to more high spec rigs that give us the ability to use 7500 psi pumping systems that have the more advanced moving systems so we can move across the pad efficiently.

All of those things will contribute to a little bit more upward pressure commercially on services and goods, probably in the second half of the year. And it's our job to continue to work to offset those.

And then in Oklahoma, a couple years ago you talked about in a lower price environment, it wasn't as competitive. And you've talked about the improving technology that's made the SCOOP work and extended reach laterals. Can you talk about the STACK and the extension of the southern Mississippi, and of what your seeing there, and how that works in this commodity price environment?

Yes. Our early results in the southern Mississippi trend, or the STACK, are very, very encouraging. As we look at liquid yields and overall performance, we feel very encouraged. Given that there is remaining consolidation and greenfield leasing opportunities there, we've been somewhat quiet on sharing specific well results, because we still see some competitive advantage to -- based on our knowledge base of the play now, to continue to go out and grow and consolidate that position. But, we feel today that, based on very early results, that southern Mississippi trend will get in and compete for capital allocation.

All right. Thanks, guys.

Thank you.

Jeoffrey Lambujon, Tudor, Pickering & Holt.

Good morning. Thanks for taking my questions. On the Bakken enhanced fracks, looking at the public data shows that in 2013, you averaged 8000 pounds of proppant per stage on 30 stages. Can you talk about what you're seeing -- or what you're testing leading-edge, and where on your acreage you're testing that?

Absolutely. Well, certainly for us, we're looking across all the variables in completion design. Of course, in the Bakken, our standard completion has been the notional 29-, 30-stage completion, with a little under 3 million pounds of proppants. Typically, that's been a sliding sleeve. And again, that's using our 320-acre spacing model.

What you're going to see going forward is that we're going to drop that stage spacing, which, of course, will have the effect of raising our number of stages per well. You'll see us looking to test variability in frac volume loading -- how much volume we're actually pumping. And then, as you state, we'll also look at moving the proppant loading to much higher levels. In fact, we have trials that will take us up to 6 million pounds per completion.

We'll also be looking at different frac designs, using both the hybrid fracks, which combine slickwater and more conventional proppant, as well as straight slickwater, as well. Given that we've been primarily sliding-sleeve completions, we're very interested and also testing the cement liner with plug and perf.

So, we've got a variety of variables. That's why we're going to be so active in the second half of the year, is that -- We think we -- because of the quality, because of the materiality of our position, we think we can move a bit more aggressively on both downspacing, as well as completion design.

And that's really what you're seeing in the second half of the year. And that will be in, really, the core areas of our play, Jeoffrey, Myrmidon, Hector and Ajax.

Great. Thanks for that detail. Switching to the Eagle Ford. Just going back to the proppant side there of those enhanced completions, can you talk more about your running room that you've got for further testing there, and what you're experimenting with leading edge there, as well? Thanks.

Yes. Similar, I would say, to Bakken, it starts with continuing to drive downspacing. We, largely speaking, now are at 40-acre spacing for the bulk of our core acreage that we're developing. But with that, as I mentioned earlier, our standard design now is around 250-foot stage spacing. But, we're looking at even taking that lower than the 250 foot, which will have the net effect, again, of having more stages in our designs.

We're also, similar to Bakken, looking at higher volumetric loading in terms of frac volumes, as well as higher proppant loadings. Both of those will be key variables that we're taking a look at. And we'll even look at some of our chemical additives that we use with the jobs that we pump, the surfactants that we use, et cetera, to see if we can find efficiencies there, as well.

There's still, in my view, running room there. In the Eagle Ford today, we've essentially offset any potential negative impact from downspacing the 40 acres by continually improving our completion design and delivery. And, we anticipate that continuing.

Thank you.

Scott Hanold, RBC Capital Markets.

Thanks. Good morning.

Question on the upper Eagle Ford. You obviously talked about some successful wells there. Can you give us a sense, when you step back and look at your entire Eagle Ford position, how much do you think could be perspective for it? When you look at the nine wells you are currently drilling, how much the rest of your acreage are you testing right now?

Yes. Just to be absolutely clear, when we talk about upper Eagle Ford, we tend to talk about the Austin Chalk and upper Eagle Ford as a unit together. When we talk about in the release about the 15,500 net acres that we've delineated, that really is the combined Austin Chalk/Upper Eagle Ford.

We're continuing that delineation program, Scott. We wanted to get out some of the positive news this quarter, because we have de-risked now this 15,500 net acres, which we believe will be developed on nominally 40-acre, 60-acre spacing going forward. We want to continue that delineation plan. You talked about the additional wells that we have activity on, and those are just going to continue, we hope, to add to that 15,500 net acres.

Okay. Then, just to clarify, when you all give your resource update late in the year, will you have a pretty good sense of your entire acreage position and how much of that has upper Eagle Ford/Austin Chalk potential?

That's absolutely our plan, is to give more -- based on where we are at that point in time, we will connect the dots between the net acreage that we've been able to de-risk and the resource potential and well inventory that that will deliver.

Okay. And my follow-up. In the Bakken, on your 12 wells per DSU test, can you remind me, how are you drilling those? Are they going to be six Bakken and six Three Forks? And will those Three Forks be all in that upper bench? Or are you planning on doing any chevron in some of the lower benches on that?

Yes. You're spot on, Scott. These will be the six-by-six, with six middle Bakken, six primarily in the Three Forks first bench. We do have some activity.

We've, of course, been involved in the other benches of the Three Forks through our joint interest business in Bakken, our OBO business, but it is our intent to also test in our operated wells some of the lower benches a bit later in the year, as well. But, our primary objective is getting the 12 wells per DSU utilizing the middle Bakken in the first bench of the Three Forks.

Okay, thanks.

Thank you.

Pavel Molchanov, Raymond James.

Thanks for taking my question. Mostly answered. One on [continue], if I may. You mentioned that Sala-1 discovery, given that it's natural gas, what can you guys do with that?

Well, certainly, Sala-1 is a gas discovery. Sala-2, which is already spud in the third quarter, we'll be appraising the size of that development of that resource. In terms of development, of course, that area of the world needs gas, needs power infrastructure. So, there are paths to monetization there for gas. For us, of course, we would prefer to keep the bias toward our liquids waiting, but we do see opportunity here.

With the Sala-2 appraisal, it will give us a view of the size of the prospect, and then we'll start talking about how best to move forward with the development. What I'll stress, though, is the discovery there -- is one discovery on blocks that are multi-million acre blocks. This is just one part. And the fact that this proved a working hydrocarbon system with reservoir quality is notable and important.

Okay. And then one on Kurdistan, following up on the question of maybe 10 minutes ago. In the context of the fighting, has there been any slowdown in activity, bringing in personnel, and in particular, I'm thinking about the development of the Atrush block, which I know you guys were hoping to bring online next year.

At this point, Pavel, I would say we haven't experienced any material impact on either our drilling operations or on the go-forward development work at Atrush. We've continued with the development wells at Atrush per plan. To date, and again, we're only as good as our last day of operation there, but to date, we just haven't seen a direct impact on our operations.

Okay. Clear enough. Appreciate it.

Thank you, Pavel.

Amir Arif, Stifel Nicolaus.

Thanks. Good morning, guys.

Good morning.

Just a quick question for you. When you think of the large proceeds coming in from Norway, how do you think about maybe using some of that to do a large, bolt-on acquisition in one of the existing areas or a new area? And just comparing that against your inventory, especially at a higher activity level, in terms of your comfort level with inventory in your three key resource plays.

I would say, again, our first call is going to be on organic growth. We feel very strongly that our inventory is solid. And as we look at the performance, not only in the second quarter, but look at the activity in the second half of the year, we anticipate forward positive pressure on our resource size across the resource plays. We have very high confidence in our organic opportunities.

Having said that, we would never rule out another use of capital. But, we're very comfortable with our organic investment. We also have the option to look at opportunistic share repurchases, as well. We feel that we've got ample internal opportunities for the deployment of the Norway capital.

Okay. But, in terms of the return potential or opportunities that you see right now, could you just provide some color on acquisition versus organic growth?

Again, our immediate view today is that we have the organic opportunities that will compete very favorably for the redeployment of the Norwegian capital, and that really is our case to beat. And, in fact, that's one of the reasons why we'll be testing very thoroughly, as part of our business planning process, our ability to further accelerate in the US resource plays.

Okay. And then just a follow-up question on the share buybacks. Is the timing of that dependent on the proceeds coming, in or will that -- should we think of you using up pretty much or maintaining the current pace of share buybacks?

We don't have a current pace of share buybacks. We have been an opportunistic share repurchaser. That will continue, and the timing of that will be a discussion with the leadership team and our Board, when that occurs. We have a remaining $1.5 billion of repurchase authorization that's outstanding, and so we have that flexibility available to us.

Okay. Thank you.

Thank you.

Jeffrey Campbell, Tuohy Brothers.

Good morning. This is the Theo Meryanos for Jeffrey Campbell. Can you guys just touch on the mix for liquids in the Oklahoma resource plays?

Yes. We've talked about that. Certainly, on an incremental well basis, as we've quoted, our numbers in the SCOOP XL, we've tried to be very transparent on the liquid content. Our most recent IP is right around 64% liquids.

We, of course, have a bit more exposure there to NGL pricing in Oklahoma. But, as we look again at the incremental well economics in the SCOOP, we find it competing very favorably for capital.

And again, as we continue to grow and consolidate that position, there's no doubt that Oklahoma is a candidate for moving to a much higher scale in the future. We're only currently running four rigs in Oklahoma, which are largely dedicated toward ensuring we hold our very high quality SCOOP acreage.

Great. Appreciate it. And can you touch, how many location -- or potential recompletion locations -- might you have if the Hector area recompletions are successful?

If we're successful, if we move through 2014 successfully, we would anticipate having an inventory of about 60 recompletes going forward, based on our current analysis.

Great. Appreciate it.

Thank you very much.

We have no further questions at this time. I'll turn the call back to Chris Phillips for closing remarks.

Thank you, Ellen. And we appreciate the questions and interest in Marathon. If you have any additional questions, please don't hesitate to call myself. We hope you have a wonderful day.

Ellen, thank you. This concludes today's conference call and you may now disconnect.

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