馬拉松石油 (MRO) 2018 Q2 法說會逐字稿

Welcome to the Marathon Oil Second Quarter 2018 Earnings Conference Call. My name is Paulette, and I will be your operator for today's call. (Operator Instructions) Please note, this conference is being recorded.

I will now turn the call over to the Zach Dailey. You may begin.

Thanks, Paulette, and thanks to everyone for joining us today. Last night, we issued a press release, slide presentation and investor packet that address our second quarter results. Those documents can be found on our website at marathonoil.com.

Joining me on today's call are Lee Tillman, our President and CEO; Dane Whitehead, Executive VP and CFO; Mitch Little, Executive VP of Operations; and Guy Baber, our new VP of Investor Relations. It's been a pleasure working with everyone in IR over the last several years, and I'm very much looking forward to my next opportunity here at Marathon. We're excited to welcome Guy to the team, and he and I will work together closely over the next few weeks to ensure a seamless transition.

Today's call 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. I'll refer everyone to the cautionary language included in the press release and presentation materials as well as to the risk factors described in our SEC filings.

With that, I'll turn the call over to Lee, who will provide a few opening remarks before we turn to Q&A.

Thanks, Zach, and I want to extend my welcome to Guy as well, and thank you to everyone joining us this morning.

With half of the year behind us, our outstanding operational execution across our differentiated position in the 4 best U.S. resource plays is driving improved corporate level returns and enabling us to exceed our production commitments for the quarter and for the full year.

Through the compelling combination of better well performance and greater drilling and completion efficiencies, we've raised our guidance for annual improvement and corporate cash returns and cash flow per debt-adjusted share as well as annual oil and BOE production growth for total company and the U.S. resource plays. All of this, with no change to our $2.3 billion development capital budget, and while adjusting for recently divested noncore oil volumes.

While development Capex has been slightly weighted to the first half of the year, we expect to see our working interest moderate across the U.S. resource plays, consistent with the planned well mix for the second half of 2018.

Our outstanding operational execution, coupled with our capital discipline and higher oil prices, enabled us to generate about $250 million of organic free cash flow during the second quarter, building upon our already peer-leading financial flexibility. This developing trend enhances our confidence in sustainable free cash flow and gives us ample room to progress multiple high-return uses of cash.

Though all options are on the table, our philosophy has not changed. It starts with a superior balance sheet and ensuring adequate cash on hand to run the business; continued discipline on our $2.3 billion development capital program, regardless of commodity pricing; appropriately funding low-cost, high-quality resource play exploration with a goal of generating outsized full cycle returns; maintaining optionality around small bolt-on opportunities in the Northern Delaware and also in our other U.S. resource plays; large M&A, however, is not our focus; and returning cash to shareholders.

We have a $1.5 billion share repurchase authorization in place and are already funding our existing $170 million annual dividend. Our framework stresses line of sight to sustainable free cash flow generation, while striking the right balance between low-cost resource capture and direct return of capital to shareholders. In the current pricing environment, we are increasingly confident we can do both. We recognize that resource capture opportunities will be episodic and will include greenfield leasing, exploration drilling and seismic as well as small bolt-ons. As such, we must be prepared to act thoughtfully, but also quickly when such opportunities meet our criteria. To that end, we spent about $250 million in the first half of 2018, predominantly on leasing in the emerging Austin Chalk play in Louisiana, and expect another $100 million to $150 million of REx Capex in the second half of the year, when we'll spud our first exploration well in Louisiana.

Highlights for the quarter were numerous, but I'd like to underscore just a few. Impressive well results continue to confirm our expanded core in both our Bakken and Eagle Ford positions. Significantly enhanced well performance in the Hector area and Atascosa County are uplifting economics and inventory quality, while both assets continue to generate significant free cash flow.

Bakken grew oil production 14% sequentially and continued its basin-leading performance with the Winona and Mamie wells in West Myrmidon, setting new basin oil records for the Three Forks, with average IP30s greater than 3,000 barrels of oil per day. Our successful expansion of enhanced completion designs into Elk Creek elevates the economic returns for yet another area within our overall lease position. As we continue to bring on basin-leading wells, we are proactively managing gas capture to remain in full compliance with all of North Dakota requirements, and expect no flow assurance issues as we continue to develop this high-return program.

Eagle Ford production grew 2% sequentially, with another quarter of consistent results from the 39 wells we brought to sales, which delivered average IP30s of about 1,900 BOE per day at a 66% oil cut. We continue to see year-over-year improvement in well performance, with 90-day cumulative production up 50% relative to 2016. The Eagle Ford again contributed significant free cash flow through the powerful combination of well performance and strong LLS-based oil realizations that were once again above WTI.

In Oklahoma, we are shifting from stacked leasehold protection to primarily multi-well pad development in both the overpressured STACK and the SCOOP Woodford. That development focus is delivering results, with the SCOOP Woodford infill, the 4-well Lightner pad on a half section, boasting an impressive IP30 of over 2,600 BOE per day from lateral lengths that averaged 6,800 feet. Importantly, initial oil cuts exceeded expectations at almost 50%, placing these among some of the best Woodford oil wells in the play.

Though our Oklahoma wells to sales were weighted to the first half of the year, our remaining 2018 completions will come primarily from the Irven John and HR Potter overpressured STACK infills. The majority of the team's activity in the second half of the year will be focused on drilling multi-well infill pads that won't come to sales until 2019.

In the Northern Delaware, we've made great progress capturing drilling and completion efficiencies, including a 45% improvement in average drilling feet per day since the fourth quarter, and averaging 9 frac stages per day on the 3-well Fiddle Fee pad. These efficiencies allowed us to move from 5 to 4 rigs in June, while maintaining our original 2018 guidance of 50 to 55 wells to sales.

On takeaway. Though an important growth asset, Northern Delaware accounts for only about 5% of our production mix for the quarter, but we are already advancing midstream solutions that, beyond protecting flow assurance, maximize margins through enhanced realizations and LOE reduction. Specifically, we have expanded our oil-gathering agreements and are finalizing a term oil sales agreement. And we just recently executed a water-handling agreement in the Malaga area that will significantly reduce our unit LOE. All of this is supported by our Midland-Cushing basis hedges at a discount of less than a $1 to WTI.

Outside of our 4 U.S. resource plays, we continue to generate value from our world-class integrated gas development in EG, which contributed over $190 million of EBITDAX for the quarter.

Also in Q2, we executed an HOA to process backfill gas from the Alen field through our LNG plant on Bioko Island. We continue to view our EG infrastructure as being uniquely positioned to become the natural point of aggregation in the region to capture additional equity and third-party gas.

I've always said that we'll never be done with portfolio management. And along those lines, we recently closed on the sale of 3 noncore, nonoperated conventional assets in the U.S. These assets contributed 5,000 BOE per day in the first half of the year, and were about 75% oil. Even with these volumes adjusted out, we still raised total company 2018 oil and BOE guidance. We are also on track to fully exit Kurdistan before year-end, representing our eighth country exit since 2013.

Second quarter has again demonstrated the strength of our returns-driven, multi-basin business model. We have the flexibility to take advantage of opportunities without being forced to accelerate into headwinds. We remain solidly on track to deliver a strong rate of change in our key financial performance metrics, with a 70% annual improvement in corporate cash returns at strip, while also delivering free cash flow. In the second half of the year, we'll continue to focus on consistent execution, while managing those elements of our business within our control: balance sheet, cost structure, portfolio simplification, that collectively generate compelling corporate returns with profitable growth an outcome.

Thank you. And with that, I'll hand it back to the operator to begin the Q&A.

(Operator Instructions) And our first question comes from Doug Leggate from Bank of America.

Lee, I think, your consistent execution really deserves to be applauded, because I think you've really done a great job turning this thing around since you came here. So I just wanted to say congratulations on a great quarter.

Thank you, Doug.

I did want to make a couple of questions regarding the cadence of your relative activity going into the balance of this year and into next. First of all, in the Bakken, I have got 2 questions by the way. First of all on the Bakken, it looks like you've got quite a wide range of variability across those Three Forks wells. I'm just wondering if you can touch on what's driving, I mean, tremendous wells on one hand, but, obviously, you've got some wells at the other end of the spectrum as well. So what's driving the differences in completion? What's happening to the underlying decline rate with your ESP strategy? And just give us some idea of what -- how you see the cadence of the Bakken over the next, let's say, through the plan period through 2020?

Yes, maybe I'll take a little bit of that question, then also let Mitch chime in. First of all, just on cadence. Per our plan this year, we are going to have a bit of waiting from a wells-to-sales standpoint in the fourth quarter. So you should expect to see that as the year plays out. From an overall activity standpoint, we continue to try to maintain a level of activity that optimizes, if you will, the continuity in our crews both on the drilling and the completion side in the Bakken. With the success though that we have seen, particularly in the Hector area and certainly not only the Middle Bakken and the Three Forks, we continue to be very encouraged about what Bakken activity might look like as we begin planning for 2019. And in terms of variability, and I'll let Mitch maybe chime in a little bit on that, we are going to see some natural variability across the play as the geology varies. But having said that, I think when you look at the consistent outperformance using our enhanced completion design, that is very much a common element. And then from an artificial lift perspective, we continue to take full advantage of the best available technology. We think managing the life of the well is equally as important as generating early IP30s. And so our team and the asset is very focused on how best to optimize using not only ESPs, but also other forms of artificial lift. So with that, maybe Mitch, if you want to chime in anything else, just on the Three Forks specifically?

Yes, sure, Doug. I think, Lee covered it at a high level pretty well. What I would say is we've talked about before the tremendous technical database that we have here, and the integrated workflow that we've applied on a subregional basis to optimize across the play. Lee aptly noted, we do see some geologic variation across the play, and we've also talked in the past about instilling a culture where we're never satisfied with yesterday's results. So we still continue to trial various designs, which would alter pumping strategy, proppant loading and diversion technology. And so some of the variability is driven by those trials as we look to optimize on a return basis across the entire play. But in aggregate, with the expansion of the core into Hector and now Elk Creek, when you look at performance in aggregate being up over 100% since 2016, I feel good about the capability and the commitment of the team there to continue to drive further improvements.

Forgive me guys. Like, I just want to get a clarification on here. Is it a workover risk when -- with an ESP strategy? Or as these things -- as the liquid volumes increase with water-cut and so on? Or is that not an issue?

We've got a pretty extensive use of ESPs that we migrated to over the last few years in the Bakken. We see that as a way to uplift returns through maximizing production through the early phases of the well life. And so I don't -- I'm not entirely sure I understand or if I'm answering your question on workover risk. But we've got dozens of ESPs in the ground, longest of which are probably more than 3 years old or have been in service for more than 3 years. And so it's a natural part of our business up there. It's probably how I would characterize it...

And if I can just add. Clearly, we're always focused on how to enhance the reliability of ESPs, and we keep very close watch on mean time between failures, which, of course, these are pumps; and over time, they will have wear and tear on them. And so the further that we can extend that useful life of the ESPs, that will, obviously, cut down on the intervention required from a well work standpoint.

Lee, my follow-up. Just a real quick one. Are you comfortable with the current rig allocation after moving the rig out of Delaware? And is the current activity in the Delaware enough to achieve your HBP requirements? I'll leave it there.

No, absolutely that -- well, first of all, just for absolute clarity on the rig drop in Permian, that was really driven by the excellent work from the Permian D&C teams there that have really captured very really early in our cycle there, in Northern Delaware, some significant efficiency gains. And what that has translated into is that we could deliver our program, which was designed to not only protect our leasehold, but also generate learnings as we get into the early kind of appraisal, kind of drilling work that we're doing there. And we could do that all and do it with less rigs and match that -- those rigs up with the dedicated frac crew that we're running in the basin. So that was a great outcome. And it is purely efficiency driven. And again, matching up with the one dedicated frac crew, we are, without a doubt, going to achieve all of the objectives there that we set out for 2018, around not only leasehold, but also continuing to understand the basin. We had some multi-well pads that we even talked about this quarter. So that work is all on track.

Our next question comes from Brian Singer from Goldman Sachs.

You highlighted your ability to execute on 3 uses of capital, or rather free cash flow: the resource capture, bolt-ons and return of capital to shareholders. Can you talk about the buffer you would want to see in your balance sheet for the first 2 of those to have more confidence in -- to execute on the third, return of capital to shareholders, i.e., what are you looking forward to kind of pull the trigger on share repurchase within or beyond your existing authorization?

Yes. Brian, I think the best way to think about it is, first of all, on the balance sheet side, I think with all the great work done by the team in 2017, we feel very comfortable with the way we have the balance sheet positioned. When we look at net debt to EBITDAX on a forward-looking basis, we feel very comfortable with how we've positioned that. So we can kind of, I believe, set that one to the side. We don't have another maturity until, well, out in time, 2021. So I think, let's just kind of park that one.

I think coming back to what are we looking for, I think we've been very consistent in the messaging there, which has been around, we want to see sustainable free cash flow being generated from our model before looking at incremental direct return of capital to our shareholders. And I say incremental, because, of course, we do still have, what, within our peer group, is still a very competitive dividend that we're paying. I think as we continue to gain that confidence and see this trend, it really started in earnest this quarter with $250 million of organic cash flow. And we used organic cash flow because we think that's more indicative of the underlying performance of the business. But as we look at that and gain that confidence and look out in time, I think we're getting more comfortable that we can accommodate not only the needs we have in resource capture, but also looking at options to return directly to shareholders. And as you stated, we have the authorization in place. We are certainly not going to preannounce any execution though against our existing authorization.

Great. And then my follow-up is with regards to the Bakken. You highlighted your ability to apply enhanced completion techniques outside of the core with the Bear Den pad. And I wondered if you could add any color on how widespread those implications are to your noncore Bakken position? And any further plans there versus more of a regional impressive well performance in this area?

Yes. No, I think just, again, to put Elk Creek in a little bit of a perspective, it still is a really -- it's still a constrained area there. It's not as aerially extensive as what you would see in Hector. But what it does is it continues to confirm our ability to go in and not only predict performance, but be successful at delivering against that prediction. I think what we want to think about though is that we have 2 very key tests coming up in the remainder of the year. One of those is pushing further south in our Hector acreage, more to the south of that place. So we feel very good about the northern part of Hector and feel that we have essentially derisked that and moved it into the core. But we do have a test to the south. And then the other test, of course, will be in the Ajax area. And both of those tests will be later in the second half of the year.

Our next question comes from Pavel Molchanov from Raymond James.

You made a point in the press release and the verbal comments to highlight the lack of gas flaring on your North Dakota acreage. I don't think you've drawn attention to that issue before. Did something change, policy, regulatory or anything like that, that encouraged you to kind of single that out?

No. Not at all. In fact, the reason we wanted to highlight that is just to assure folks that as we see more activity in the basin, as North Dakota continues to -- their regulatory regime around gas capture, that we kept everyone up to speed on our view of that. And that we are not only in full compliance, but certainly don't see any impacts on our forward development plan there. So it's really just more confidence setting. And I think, it's also important to -- I know that the state does put out data on flaring and sometimes that can get confused relative to actual compliance, and we wanted to be absolutely clear that we were in full compliance, no impact relative to our forward development there in the Bakken.

Okay. In Q2, you had 13,000 BOE a day of U.S. production outside of the big 4 resource plays, and your sold looks like 4,000 of that since. Where is that -- the remainder, I guess, 9,000 BOE a day?

Yes. It's kind of distributed out. There's still a bit of an element in the Gulf of Mexico. We still have a couple of small assets in the Gulf that are largely contributing to that bottom line in the North -- and the remaining kind of North America production.

Okay. And are you -- is it safe to say that you would be looking to kind of continue cleaning that up?

Yes, I think we're kind of in the nits and gnats at this point. In the U.S., there are smaller, if you will, assets, but we'll continue to look to monetize those to the advantage of the shareholder, just like we did in the current quarter. And it's just part, as I said in my opening comments, we never view portfolio management as being done. We're constantly looking to upgrade, simplify and concentrate the portfolio, and you should expect us to continue to do so.

(Operator Instructions) And our next question comes from Jamaal Dardar from TPH & Company.

Just had a quick question, you mentioned looking at the free cash flow in your model in order to determine maybe the pace and execution of buybacks. I just wanted to get a sense of current strip ballpark. What you all are seeing in terms of free cash flow over that 2021 plan?

Yes, we haven't talked about -- Jamaal, sorry, this is Dane Whitehead. Yes, we really don't forecast out to 2021. But we want to think about the rest of 2018. I think the fact that we generated $250 million of organic free cash flow in Q2 with commodity pricing environment that's very similar to what we're looking at for the balance of the year right now, it's kind of reasonable to think that we will generate that kind rate, I believe, for the rest of the year.

All right. That sounds good. And just moving operationally, you saw some really good results here in the oily Woodford play that we haven't seen in a while from you all. Just kind of wanted to get an update on the size of the opportunities set there. You haven't been updating on the resource in some time, and I guess, the data disclosure was that, maybe that was a little lower working interest. So just kind of want to get an update there.

Sure Jamaal, this is Mitch. I might refer you to Slide 12, where we kind of highlight the near-term activity in Oklahoma. And you'll note a number of multi-well infill pads down in the SCOOP area in the general area of the Lightner. We have been talking about for the last couple of quarters this pivot from STACK leasehold protection to a focus on infill development drilling in high confidence areas in the overpressured STACK and SCOOP. We think -- we've got plenty of running room in and around the Lightner. You see the near-term activity there. I think the Lightner is a really good indicator of the type of deliverability and returns that we would expect from that area. We would expect some variability in oil cut, as Lee highlighted. The Lightner came in above expectations on oil cut, but from a returns and deliverability perspective, the activity that we've highlighted there for the remainder of '18 in terms of infill drilling pads, should expect similar kind of economic results as we saw on the Lightner.

Our next question comes from David Heikkinen from Heikkinen Energy.

I was thinking through and comparing other companies in the Delaware. Many pointed to higher OBO spending driving higher CapEx. I was just wondering if you guys are seeing the same trend in OBO that could impact your budget for the remainder of the year.

David, this is Lee. Just maybe I'll address OBO just in general. It's an element of our business that's particularly relevant in both Oklahoma and Northern Delaware. It's also notoriously one of the more challenging ones for us to predict and build in to our modeling as well, because you're somewhat reliant on the feedback that you get from the other operators. And of course, their plans change, their capital allocation may change, their timing and pace may change. But I think in general what I would say is that we've had to, like many, watch very carefully the OBO spend. And we treat OBO spend just like we would on our own operated spend, we're returns driven. And if we don't see adequate returns, then we will not support those investments. So with activity increases, there will be a natural bias up in not only operated activity, but also nonoperated activity. So it's just like any element of our business. We're managing it. We're managing it based on returns. And it's fully contemplated in our $2.3 billion capital budget.

I'm not trying to read between the lines. Does that say you're -- you got plenty of free cash flow, so it really is just purely returns. You're not drawing a hard line on $2.3 billion. Like, commodity prices are up, so I'd expect returns would be good. So that would just -- in Oklahoma and Delaware that bias should budget a little higher just given activity level.

Yes, I mean, I would say within the $2.3 billion, obviously, there's been puts and takes throughout the year. OBO is just one element of that. But we are going to support high-return opportunities, whether they be nonoperated or operated. And -- but it has to come in and compete for capital allocation just like any piece of our business. So no, we're not going to artificially constrain and make poor business decisions.

Our next question comes from Devin McDermott from Morgan Stanley.

I wanted to ask on the resource play exploration strategy. You've acquired a large position in the Austin Chalk at this point, as you noted an attractive low cost of entry. As we think about how that strategy there plays out over the next several years and the overall spending profile for resource play exploration, is it now going to focus more on the exploration and appraisal on the Austin Chalk? And that's where -- that spending will largely be bucketed? Or are there other opportunities that you'll continue to look at beyond that as we move toward getting more information on Austin Chalk over the next several years?

Yes. Well, certainly, the REx opportunity set is much broader than just Austin Chalk. There are numerous opportunities that, that team is actively engaged in today. I would point out though that the Austin Chalk in Louisiana, it is a unique opportunity in terms of its scale and the entry point there. And so elements of that will be somewhat difficult to replicate in some of the other opportunities. So it is unique in that sense. So as difficult as it is to forecast this part of our business, I would say that the pace of spend certainly that we saw in the first half of the year, which was largely dominated by Louisiana Austin Chalk, that was a pretty unique opportunity set.

Got it. That's helpful. And the other question I had is actually shifting over to international, Equatorial Guinea. You highlighted in the context that potentially being a regional hub for growth in that area. I was wondering if you could just add a little bit of color on what the opportunity set is that you see there. If that's an asset where we could see growth over time and just how you're framing that.

I think our starting point is we have a -- we are very uniquely positioned in EG with that integrated gas infrastructure that we have there. We also know that there is not only the opportunity that we're currently pursuing, which is the Alen field and bringing it in as backfill gas. But we know that there is regional gas in the area that ultimately will need to find a monetization route. Some of that within EG. Some of it may be even outside of EG. But geographically, this is a very well-positioned asset and infrastructure. We know that the EG government is very keen to continue to progress their role in regional gas development, and we're going to support that initiative.

Our next question comes from Roger Read from Wells Fargo.

I guess, if we could come back a little bit, the question was asked earlier about share repos. I believe on the last conference call, you kind of gave an idea of the amount of cash you would want to have on hand. I was wondering if you could kind of refresh us as to what you'd like the balance sheet to look like before you consider increase shareholder returns, whether it's a share repo or a dividend increase?

Roger, this is Dane, again. We feel like -- as Lee said earlier, we feel great about where the balance sheet is right now from a leverage perspective, net debt to EBITDA is trending sub-1x, which is, I think, kind of top of the peer group. And we don't have any current maturities, next one is in 2020 and it's $600 million, should be easy to handle one way or another. From a managing the business perspective, we've been pretty consistent saying, it's nice to have about $750 million in cash on hand. Intramonth, we see some fairly significant swings, as receivables come in, as payables go out, and we also want to have a little bit of flexibility to do bolt-ons or the REx activity from time to time with short notice. So that's sort of the minimum operating level we like to maintain. We're feeling -- obviously, we're in a better position right now than that from a cash perspective, which gives us the flexibility to do the things that Lee mentioned in his opening comments. I mean, we have -- we can balance our approach with adding future inventory at low cost that can generate high full-cycle returns and also give due consideration on return of capital to shareholders. And so we feel pretty good about that. And as we continue to generate free cash for the balance of the year, that will give us additional flexibility.

Okay. I guess, a follow-up on that. So obviously, the move here into the Austin Chalk relatively attractive lease cost. As you think about acquisitions, is there anything on the larger scale at this point that looks interesting or attractive? Or it's really we should think more of the smaller, I guess, you described bolt-on type positions?

Yes. Roger, this is Lee. Absolutely, we are focused squarely on the smaller bolt-ons. Larger-scale acquisitions simply are not on our radar screen. We feel that there've been -- there's some really unique opportunities in and around our core basins that are in that kind of small bolt-on category. You'll recall that we did one in 4Q in the Northern Delaware. And so that's the type of opportunity that we're going to continue to look at. What we like to do, of course, is to continue to take advantage of the amazing execution being delivered by our teams in these core assets. And it's going to be hard pressed for others to demonstrate that they can drive more value, but we want those, even though smaller, acquisitions, to come in and compete for capital allocation from a full-cycle basis. So that's the criteria that even those will have to meet to get in through the door.

Okay. Great. If I could just throw in one last one, and it's into the weeds, but on the OBO issues where you're not funding, you're choosing not to go forward with that. Any -- SCOOP/STACK you highlighted, but is that the leading resource play where you're seeing that? Or is it spread across Eagle Ford, Permian, Bakken, et cetera?

First of all, I want to be really clear. We do not expect to be in a nonconsent position on a lot of opportunities. That's not our expectation. I mean, we expect operators are going to bring forward their best opportunities, just like we are. But the areas where we have, the large -- the larger nonoperated exposures are Oklahoma and Northern Delaware. Both of those teams have an economic criteria that they test, all opportunities against, and then we make a decision on that basis. And also bear in mind that leases may have different terms associated with them too around participation. And so all of that will factor into our forward-looking decision.

Our next question comes from John Herrlin from Societe Generale.

Regarding the Austin Chalk, when will we hear test results? Will that be more of beginning of next year or early?

John, we're -- as you know, very, very early days here. We're looking to spud the initial well in -- later this year. Meaningful results are going to be later in 2019. Clearly for us -- this is an exploration play, and I want to remind everyone of that. So it's going to take us a bit of time to get our arms around what the data is really telling us. And it is going to be a relative limited -- relatively limited data set even at that point in time. In parallel, we're also participating in a multi-client seismic survey, which is also going to support whatever well results we get. So the integration of all of that data is ultimately what will decide whether or not this is something that we want to take into more of a development mode.

Okay. That's fair. Assuming it does go ahead, how is the infrastructure there in terms of access, midstream, et cetera?

Yes. Well, clearly, there in some areas of the Chalk in Louisiana, there has been, I would say, more conventional development that kind of goes back into the kind of the 1990s. But I would say that infrastructure will be one of those areas that we have to focus on initially in ensuring that we get out in front of that. But from a geographic location standpoint, I like being close to the Gulf Coast. I like the fact that this is an area where there has been hydrocarbon development in the past. So -- and that way it's very similar to places like Oklahoma and South Texas, where even though we brought in the unconventionals, there was a conventional business there that kind of came in before us. And, of course, we're going to certainly enjoy having indexing more to an LLS basis than somewhere else.

Our next question comes from Vin Lovaglio from Mizuho Securities.

It's Paul Sankey here. I jumped on to Vincent's line and maybe we should get -- force him to ask the question, but it does (inaudible). The -- I'm always fascinated by your position right across the U.S. unconventionals, but it seems to me there must be very challenging plan given the scale of changes that we're seeing, whether it's in differentials, whether it's geologic performance. And of course, I was wondering as well how costs are changing in the different regions. Can you talk a bit about all of those things? It feels perhaps like the Bakken is much more attractive now based on transport differentials. It feels like Oklahoma might be dropping off a bit geologically. And then your perspective on drilling and completion costs as well.

Yes, certainly the multi-basin model in our opinion offers a lot of advantages, but it does require a level of planning and optimization that is different than if you were in a single-basin mode. There are a lot of different factors that go in. Obviously, you're getting new performance data each and every day. You're getting new cost data, you're getting new realization data each and every day. So our planning processes, we've completely overhauled them to reflect the realities of the unconventional plays, which means capital allocation is no longer once-a-year exercise. It's something that we do in real time. And so you should expect to see us continue to adjust and flex as we see developments in each of the individual basins. And whether that's some type of dislocation from a realization standpoint or some kind of dislocation even on a cost standpoint, we do have the ability to reflect that in our allocations going forward. There's little doubt though that when you look at somewhere like a Bakken, where you've had the combination of both productivity gains, strong realizations and continued reduction in the cost structure that those barrels are going to be extremely competitive even within our multi-basin model, and that's why you see us driving a lot of capital in that direction in this year's plan. So that was our perspective when we started the year. I think the -- probably the pleasant surprise for us has been the sheer outperformance of what had traditionally been these noncore areas, like Hector, and seeing them compete head to head with the Tier 1 inventory that we have across all of our basins.

Right. And then, of course, I've seen that the Tier 1 has cost disadvantage because of the larger amount of activity in those area.

Yes, I mean, I think it varies. I think a lot of kudos to our supply chain group and the operations teams working with them that, they have continued to find innovative ways to control our cost structure. Whether that is looking discreetly at things like local and regional sourcing of materials, including sand. I think the month of June, we sourced all of our sand locally in the Permian, for instance. So we're looking, for instance, at continuing to assess ways to broaden our vendor population and open up our services to a broader cross-section of vendors. And we're even considering potentially terming up some element of our activity to ensure that, again, we not only have the security of well-trained, strongly executing crews, but also can potentially lock in some favorable commercial terms.

And I'm showing no further questions at this time. I will now turn the call back to Lee Tillman for closing remarks.

Thank you. I want to conclude by thanking all of our dedicated employees and contractors that deliver excellence in all they do 24/7. Welcome, again, to Guy. And certainly, thank you for your interest in Marathon Oil. That concludes our call.

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating, and you may now disconnect.