馬拉松石油 (MRO) 2014 Q1 法說會逐字稿

Welcome to the Marathon Oil Corporation 2014 Q1 Earnings Conference Call. My name is Tiffany, and I will be your operator for today's call.

At this time, all participants are in a listen-only mode. Later there will be a question-and-answer session. Please note that this conference is being recorded.

I will now turn the call over to Mr. Chris Phillips. You may begin.

Good morning, and welcome to Marathon Oil Corporation's first-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 J.R. 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, and our comments and answers to questions will contain forward-looking information subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. I 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. Good morning to everyone joining us on the call and the webcast. Prior to opening up to your questions, I want to make a few brief remarks on our first-quarter performance.

We delivered strong financial results in the quarter, underpinned by continued production growth across our US resource plays, coupled with strong realizations and lower exploration costs. Our adjusted net income per diluted share increased to $0.88, up 73% from year-ago quarter.

First quarter of 2014 production available for sale from continuing operations excluding Libya, averaged 440,000 net barrel oil equivalents per day. And was impacted by an estimated 6,000 net barrels of oil equivalent per day associated with extreme winter weather. And by an estimated 14,000 net barrel oil equivalent per day related to lower reliability on non-operated assets.

Importantly, we've already advanced the three key priorities of our 2014 agenda: Ramping up US resource play drilling activity, marketing our North Sea businesses, and delivering shareholder value through opportunistic share repurchases. We remain confident in our plans to grow production from our three US resource plays by 30% in 2014 over 2013, as we aggressively pursue co-development opportunities for the Austin Chalk Upper Eagle Ford, the Three Forks in the Bakken, and vertically stacked horizons in Oklahoma.

We are committed to rigorous portfolio management to simplify and concentrate our portfolio toward higher growth and higher-margin opportunities. The closing of the sales of our working interests in blocks 31 and 32 in Angola during the quarter and the ongoing marketing of our UK and Norway North Sea businesses are evidence of this resolve.

We completed the $1-billion share repurchase tied to the Angola Block 31 sale, representing 29 million shares. And in March announced an additional $500-million share repurchase, which is now substantially complete. Upon completion of this additional share repurchase there will be $1.5 billion remaining on our share repurchase authorization.

We recognize the importance of delivering on our commitments quarter-on-quarter, year-on-year. The first quarter delivered $1.35 billion in cash flow from continuing operations, 97% average availability in our operated assets, and 26% production increase in the US resource plays year-over-year, or 7% quarter-over-quarter. With our high-quality assets, deep inventory, capital discipline, and demonstrated ability to execute, we look for continued profitable volumes growth to support the strong investment case for Marathon Oil.

We would now be pleased to take your questions.

Thanks, Lee. Before we open the call to questions, we would like to request you ask no more than two questions with associated clarifications. You can re-prompt as time permits. With that, Tiffany will open the lines for questions.

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

(Operator Instructions)

Our first question is from Ed Westlake of Credit Suisse.

Yes. Good morning and congratulations on the free cash flow that you generated in the quarter. I guess some of that probably was from the North Sea. Maybe talk a little bit about how you see the sort of free-cash trajectory of the Company, excluding the North Sea, assuming that you're able to sell that? Thank you.

Okay. Thank you Ed, and good morning. Ed as we previously communicated, on a pro forma basis the North Sea businesses contribute about 20% of projected 2014 cash flow. Obviously we're watching the cash flow very carefully. As we look forward, though, post a potential transaction, it's also important to recognize that both the Eagle Ford as well as the Bakken will be going cash flow positive at current activity levels in 2015. We remain confident in our go-forward outlook and our ability to fund our investment program.

Switching to buy-backs, I guess obviously awaiting bids on the North Sea in the second quarter, but you've been pretty aggressive so far. Would you consider continuing to be as aggressive going forward? Maybe you can sort of buy-back ahead of the North Sea closing, given where the current share price is?

Maybe for a moment talking about the North Sea, I just want to confirm that's a competitive process. It's moving forward per plan. We're still on the time line that we've communicated. Our main objectives there, of course, are a full exit from the North Sea, and of course delivering shareholder value there.

When we talk about buy-backs, I would refer back Ed to our view of capital allocation. Share repurchases factor into that. They compete for capital. We've seen some opportunistic share repurchases. I'm not sure that I would call them aggressive, I would call them opportunistic. We've looked at the returns that those could generate for our shareholders, and have felt very comfortable with what we've been able to deliver in the share repurchase program. Going forward, and assuming a successful transaction, repurchases will be part of the capital allocation consideration.

Thank you.

Thank you, Ed.

Our next question is from Doug Leggate of Bank of America Merrill Lynch.

Thank you. Good morning, everybody. I wonder if I could try to say a quick one on the running room on the core development opportunities in the Eagle Ford. Specifically, obviously the Austin Chalk, and any other stacked opportunities you see in that area. You've obviously given some pretty impressive well results, but we still don't have really any feel for what the scale of the acreage, what the scale of the running room could be ultimately for that development. I guess the pace of development would come into that debate as well? If you could address those issues in the Eagle Ford, and I've got a follow-up please.

Yes, absolutely Doug. Great question. I think as I've shared with several on the line, when we look at the co=development -- and we like to call it of course, we refer to it as the Austin Chalk, but I want to be clear that it's the Austin Chalk in conjunction with the Upper Eagle Ford being co-developed with the Lower Eagle Ford. The work is progressing. Last, I would say in 2013 our task at hand was really determining the viability of those zones of the Austin Chalk and Upper Eagle Ford. For the areas where we have wells, we have fully demonstrated that viability.

2014 is really geared toward now attempting to extend that viability across our acreage position. The reason we haven't been out there with an update from a resource potential or well inventory standpoint is because we're still in that process of appraising the full potential of the Austin Chalk Upper Eagle Ford. As we complete that appraisal and then determine what that inventory is, we'll then flow that inventory into the prioritization of our full development plan of the Eagle Ford. That will ultimately dictate the pace.

I appreciate that answer, Lee, thanks. As a follow-up to Ed's question, the running room in the Bakken and I guess the Cana in the Eagle Ford roll, those obviously anchor your production, at least going forward. But how are you thinking about redeploying the potential proceeds of the Norwegian and UK sales, assuming they complete? Would that be additional buy-backs, or would you consider adding another leg to the proverbial gold stool, so to speak?

Yes, while I would say obviously nothing is off the table, but I would go back to our capital allocation discipline, Doug. As you state, we've got a deep inventory of growth opportunities across our three high-quality US resource plays. Certainly one of the first calls on those proceeds would be looking to drive further accretive investments across those three plays.

In addition to that, we will look at selective resource capture opportunities, as long as those opportunities can compete with the current inventory that we have in hand, which is quite high quality. Then as you state, share repurchases may also factor into that equation as well. We're not ruling out any options. But for a -- from a long-term shareholder investment standpoint, we feel very good about driving investment, further investment, into our three high-quality US resource plays.

Great. Appreciate the answers, Lee. Thank you.

Thanks, Doug.

Our next question is from Paul Sankey of Wolfe Research.

Good morning, everyone. Could I just keep going on that, Lee? I think there's a perception that the asset base isn't strong enough to generate long-term growth, and that you kind of have to buy something. As a fair, I know I'm hammering on the point, but I do perceive it to be the big overhang on your stock. Can you just keep coming back to this idea, I guess, that you're not going to make a dilutive acquisition, and that you believe you've got the asset base to grow the Company in a way that you think is attractive to shareholders?

Yes, absolutely Paul. I want to be absolutely clear. In fact, for those that participated in Howard Weil, we spent a good deal of time and effort trying to go through the complete resource base that we currently view in the three resource plays, which we feel is very compelling. We're looking at 2.4 billion oil equivalent barrels in aggregate, 10-plus year drilling inventory there.

As we look at further co-development, down-spacing, stacked opportunities across those three plays, we see a path toward further enhancement in that two key resource base. Our confidence is very high. We in no way feel compelled or driven toward an M&A strategy that would be dilutive. Opportunistically, any type of resource acquisition, small or large, has to compete against that existing inventory that we have today.

Great. Thanks, Lee. If you could just update us on the Gulf of Mexico, deep-water Gulf of Mexico -- what you're up to and what's happening there, and the outlook? Thanks a lot.

Absolutely, Paul. I think everyone is aware that we are bringing in the new build drill ship into the Gulf of Mexico this year. We expect to spud that in the third quarter. That would be our initial inboard Paleogene prospect, which is the Key Largo prospect. We've got currently a 60% working interest in our operator of that well. We're quite excited. This is a rig that we're sharing 50-50 with another operator.

In addition to that, we have the second appraisal well on the outside operated Shenandoah prospect, with is of course Paleogene in nature. Finally, we're looking or have farmed into the Perseus prospect, as well in DeSoto Canyon. A well there is anticipated in the second half of 2014. That is a [northlet] opportunity.

Thank you.

Thanks, Paul.

Thank you. Our next question is from Evan Calio of Morgan Stanley. You may go ahead.

Keeping with the organic inventory theme, I know you answered questions on Austin Chalk Upper Eagle Ford, but it also appears location upside from the scoop with your results. I know maybe it's while early, I didn't know if you could put any numbers around that potential, and more details on these extended laterals -- commodity mix, lateral length, IRRs, and how that's stacking up competitively within your portfolio?

Yes, absolutely. We're quite encouraged by the early results from our drilling program and the SCOOP. We communicated some 30-day IP rates from two SCOOP XL wells, which were again quite encouraging, good liquids yields, very good IPs. But the real question continues to be what's going to again be the long-term EU performance.

Really before we start broadly communicating resource and inventory impact, at a minimum we want to be able to get enough production time to confirm the underlying economics of those wells. You might recall from Howard Weil, you know we had shared some indicative economics of SCOOP XL condensate wells, and they were quite compelling when looked at our broad inventory. Based on the confirmatory results we've seen thus far in our XL program, we see at least those types of returns. Of course those were done at a relatively modest flat pricing environment, as well.

We're quite encouraged. As we've stated, we've got 100,000 net acres in the SCOOP, but we're methodically walking through our program there. We've got about 20 SCOOP wells planned for 2014 in the inventory this year. We hope to have a bit more results later in the year.

Are you testing different length laterals in the results that you reported? Where those kind of a one-mile lateral, somewhat in the continental wells?

It varies. In the SCOOP, we vary between a mile to two miles. A lot of that will be dictated by geology or by the lease configurations that we're confronted with. Sometimes we're not able to do the full XL length and we'll scale accordingly. You may have some XL minuses and some XL pluses in there.

Right. In the commodity mix, you mentioned condensate. But is there any more detail -- is there different windows there? Curious where you're drilling?

Yes, well we expect there to be some variability. We wanted to provide those some indication of liquids yield. That's we showed that 66% to 70% liquid yield on the two wells that we communicated. That's the type of economics that would look very attractive to us and compete for capital allocation.

Maybe just lastly for me, do you think it's through this 20-well program that once that's complete you'll have a better view to express a location number, resource number, similar to what you did in December, to see what the up side might be from what you disclosed then?

Certainly we'll have more data, and I think we'll have more data in really two areas. One is on the resource and performance side -- what type curves are we really observing in the wells. Really, to confirm these economics, truly you need about 180 days accumed production to really get the underlying type curve defined. But the other piece is also you have to bear in mind is that we'll also be gaining information on where we can drive capital efficiency on the D&C side, as well. It's really those two elements coming together that will ultimately dictate the resource side, and the number of inventories that we see. But we'll have a lot of more data at the end of the year.

Okay. Thanks for your comments.

(Operator Instructions)

We are taking two questions per participant, and will take additional questions as time permits. Our next question is from Guy Babber of Simmons and Company.

Good morning, everybody. My first question was on capital spending, during 1Q came in lower than we had modeled, lower than the rate implied by the full-year guidance. You guys ramped up to the 28-rig program fairly early in the year. We've been expecting pretty consistent level of activity this year. Just curious as to how the 1Q CapEx came in relative to your internal plans? Are you guys tracking below budget and maybe seeing some better-than-expected cost savings and efficiencies, or did you have some weather influence 1Q, and is the spending just going to be a little bit -- will just build as we progress through the year?

Great question, Guy. Let me take that one head-on. We are down on run rate in the first quarter, and let me give you the rationale for that. One is we had fewer wells to sales, fewer completions in the Eagle Ford. That was largely driven by the learning curve of three new rigs, the increased density in our pad drilling, moving from notionally three to four, and also extending the lateral length on our well mix. Less completions, of course, less cost.

The bigger element, though, was the timing and phasing of some of our major project spend. I'll emphasize it's a timing factor. We're not predicting that we will not spend our full capital budget for 2014. Specifically, we had some expense well work that ran into 2014, displaced some of the capital work that needed to occur on the boil-up project that will now be a bit later in the year. That really was -- the project element was the main driver. But our expectation, of course, is that is simply a timing element.

Okay, very helpful, Lee. My follow-up was I was just hoping you could provide some more information, if available, with respect to what you're seeing on the Bakken down-spacing initiative -- how the four pilot locations are progressing in your core areas, any color that you might have there? Also, could you talk a bit more about even higher-density spacing that you have planned for later in the year? What's the timing on that? When would you expect to be in a position to maybe communicate some of the comprehensive results from that program, and what it might mean to your view of the resource potential there?

Yes. Good question. As we've mentioned before, Guy, we are at the early days of the 320-acre spacing test. We refer to these as high-density pilots, because essentially we're combining eight wells there, four in the Middle Bakken, four in the Three Forks, for one 1,280 DSU. That work is progressing. We continue to see encouraging results. We don't have any new data to share.

We have shared a bit of where those cumulative oil curves were progressing in the Howard Weil. We don't really have a material update on that. We are, though, progressing into the higher-density pilot, where we're looking up to 12 wells, for 1,280 spacing units. Those will not really be spudded until the second half of 2014, and will be in both the Myrmidon, as well as the Hector areas.

Okay, great. Thank you.

Thank you very much, Guy.

Our next question is from Roger Read of Wells Fargo. You may go ahead.

I just wanted to, I guess, come back to the questions on the Eagle Ford regarding the -- as you mentioned, the increased number of rigs, the density and all that. Then you made the comment in the transcript about needing to rebuild your uncompleted well inventory. Could you just help us understand maybe how that either already has or will affect kind of well completions, production growth, as we looked over the next couple of quarters?

Yes, absolutely. Good question, Roger. We did mention that there were a few factors impacting our wells to sales in the first quarter in the Eagle Ford. Again, just to review those, those were essentially the movement to higher-density pad drilling, a bit longer laterals -- which again, that's a great value proposition for us. We're doing that because it's creating more present value on those wells. Finally, as you stated the learning curve of bringing incremental wells into the fleet.

What I will say is that if you look at the total wells to sales in the first quarter, which was 49 for the full quarter, to give you some confidence going forward that we've now crossed that bridge in rebuilding inventory. For the month of April we've already brought 26 wells to sail in the Eagle Ford in the month of April. We're back, fully on track for moving into the second quarter.

As we look out Q3, Q4, the run rate of say in April or a Q2 overall should be more indicative than Q1, or are we kind of in a bit of a sine curve, ups and downs, here?

No, I think at this stage we're looking at -- the second quarter should be much more of an indicative rate for us in terms of wells to completions. We'll again have some run time with the new rigs. The well mix may continue to create some lumpiness as we have longer laterals. Certainly our density in pad drilling is going to continue to move even from the four to higher numbers, which does create some lumpiness. Particularly as you get around the transition quarter to quarter, depending upon when some of those well pads fall, could impact the number of wells to sales, because you're now talking four, five, and six wells that could trip from one quarter to the next.

Okay, great, thanks. My last question, the OSM, another kind of bumpy quarter here. It's not unusual for that category for anyone. You've been pairing assets that haven't necessarily met your long-term criteria. Can you walk us through the thoughts on OSM? Given its challenges, given the discounts in general for Canadian crudes, how that sort of fits in with everything? Is it something that you want to fix, or it might be better off in someone else's hands?

Well, certainly first and foremost we want to fix OSM's performance. It is a high-quality mining asset. It has suffered from very challenged reliability, which has created an inconsistency in the returns that it does deliver. It is a very large resource base for us. We have about 600 million barrels in reserves associated with our interests in AOSP. In terms of how does it fit in our portfolio, I would say we have no sacred assets. I'm not going to speculate on future strategic divestitures, but we will test all of our assets in terms of their long-term fit, and we'll take it from there.

Okay, thank you.

Our next question is from John Herrlin of Societe Generale.

Hi. In the release you said you're pleased with the Eagle Ford performance being above type curve. How much above type curve are the wells doing? Are you changing your designs at all? Are you putting in more proppants or increasing frac density?

Well, our completion designs continue to evolve and improve. Again, as we talked about it at Howard Weil quite extensively, the movement and completion designs have essentially offset any impact that we might have for foreseen in the down-spacing, moving down to 40 acres.

The completion design continues to be an iterative process, where we continue to improve the value proposition. We look at all elements of completion design, proppant load and fluid loading, stage spacing, the number of frac stages, the type of stages that we're using and pumping. Here's where we really benefit from the competitive aspects of the service companies, really bringing the best available technology to the completion side. The designs do continue to move, do continue to improve.

Okay. With Key Largo, are you going to go into the well with 60% working interest, or are you going to farm it down more?

We'll take -- just like any of these deep-water Paleogene prospects, we'll look to see if it makes sense to manage risk further. Our view is we want to maintain a materiality and operatorship. But certainly we would not rule out the potential to bring in the correct partner if we saw that as an opportune chance to mitigate risk.

Great. Thank you.

Thanks, John.

Thank you. Our next question comes from Amir Arif from Stifel. You may go ahead.

Thanks. Good morning, guys. First question on the Eagle Ford. The six Austin Chalk wells that you do have. Can you just give the sense of how the 30 day in the type curve so far compares to the Lower Eagle Ford wells in the same region.

Yes, absolutely Amir. We've shown this before in previously released data, but when we compare to a lower Eagle Ford 40-acre type curve, we're seeing very analogous performance. In some cases even the Austin Chalk performance is moving ahead of the 40-day Eagle Ford. There's variability there, but we're very encouraged that the Austin Chalk Upper Eagle Ford completions are quite competitive with the Lower Eagle Ford, and more importantly in the co-development scenario, we see those two zones behaving independently. We see no impact or interference -- negative interference from the Austin Chalk Upper Eagle Ford completion.

Okay. So there's no pressure drop that you're seeing on those wells relative to the other existing wells?

Correct. We haven't seen any issue with the co-development scenario cannibalizing the Lower Eagle Ford production.

The second question is just on the Oklahoma basin. The 100,000 acres you have over there -- is that just the SCOOP? If that's the case, can you also outline how many acres you do have in the stack, and how many acres in the Granite Wash or the Mississippi play?

Yes, the 100,000 acres simply refers to our SCOOP position, our net acreage in the SCOOP position. We haven't given out specific acreage, but overall we have about 210,000 total acres in the Oklahoma resource basin. Bear in mind that things like the Southern Mississippi trend and the Cana Woodford are stacked with one another. There a components of that 210,000 net acres that are in core stacked potential, as well as things like the Granite Wash.

Have you tested the stack zone?

Yes, we currently as we mentioned in our press release, we continue to test other horizons in the Oklahoma resource basin. Specifically, we have two operated wells that are producing in the southern Mississippi trend. We have in fact brought online the first of two Granite Wash horizontals. Again, Granite Wash is a bit of a redevelopment of a field that was vertically developed. We do have additional wells in the Southern Mississippi trend scheduled to spud in the second quarter of 2014.

Thank you.

Thank you. Our next question is from Pavel Molchanov of Raymond James. You may go ahead.

Thanks guys for taking the question. First on Kurdistan, as you are getting ready to begin production on Atrush in 2015, is there a clear framework for the off-take on that? On a related point, do you have a sense of where crude pricing is going to be relative to benchmarks?

Maybe take the off-take question. Kurdistan -- the Atrush development, which is a PACA-operated development, we're looking to have three wells that will be producing about 30,000 gross barrels per day, with first oil in 2015. The original field development plans were predicated really on truckable volumes, because that was the export solution of high confidence. As the discussion continues between Erbil and Basra, we know that there are Kurdistani barrels in Turkey today. They have not been brought to the open market as of yet.

But if there is a resolution there, then clearly the path we would like to pursue would be linking into more of a pipeline export solution. It gives us much more flexibility, ensures flow assurance, and certainly would allow us to ramp up additional phases more readily in that scenario. Realization-wise, I think our view would be hoping -- hopefully driving those toward benchmark pricing, with some discount based on the location. It would be a Brent-index type pricing.

Okay. On your exploration program, given the calendar you laid out in the press release, it looks like Q2 will be -- or maybe second half of Q2, first half of Q3 -- is going to be the most high-impact period of 2014 in the program. Is that a fair characterization? Is it kind of concentrated this way?

We would certainly be getting some well results in 2Q that will be very important. We will be in the testing and TD phase of the [Gistic] 1 well, which is an important operated well. It's a follow-up to our discovery, the [Moraba] 1 discovery on the [Harir] block. You'll also see results from the Sala 1 well in Kenya and the Shamala 1 well in Ethiopia. Most of the other activity will be a bit more back-end loaded in the year.

I certainly don't want to minimize the importance, though, of that inventory relative to forward performance. That includes the operated Key Largo, as well as two potential operated wells in Equatorial Guinea from an exploration standpoint. Yes, 2Q is important to us, but certainly the back end of the year, and the wells we'll be spudding then are equally as important.

Helpful. Thanks, guys.

Thank you.

(Operator Instructions)

Our next question is from Jeffrey Campbell of Tuohy brothers. You may go ahead.

Good morning. First question I wanted to ask was on the Bakken re-completion which you announced in the press release. I was just curious to know something about the costs, and also what were your production expectations prior to the re-completion.

Yes, absolutely. We have progressed our Bakken re-completions program. We've delivered five wells there thus far in the first quarter. That program will continue through the year. We do have initial 24-hour and 30-day IP rates in hand, and those are certainly exceeding our original funding expectations. These are, though, full re-completions. These are not re-frac. You're essentially re-completing and re-fracturing the well, bringing it up to current technology levels. These are wells that were originally completed with open-hole, single-stage gravel packs, or frac packs for the most part. We're bringing those up to current technology norms.

The ranges that we're seeing for these re-completions are between $4 million to $4.5 million. As we get a bit more cumulative production and can confirm the economics, we'll come forward with that and share it a bit more broadly. We're just a bit still in the early days. I would also mention that the initial re-completions have been in what we consider to be the highest quality area of the Myrmidon. We're now extending that into the Hector area, as well. When you look at that 100-well inventory that we quoted at Howard Weil, these are important tests to see just how much of that inventory will be within the economic window.

Okay. To make sure I have a little idea what we're talking about, when you're talking about maybe going in and taking an open-hole well and maybe doing a cement liner, and plug and perf, the kind of stuff that we see evolving in the new wells in the Bakken -- is that what we're getting at?

Yes. Basically, we're taking these wells and re-completing them using the best available fracturing technology that we're applying on our new drill wells, which for us may be sliding sleeve type completions -- whatever we feel is the best completion for that area of the Bakken.

Okay, that's very helpful. Sticking with the Bakken, I just wondered if you have any update on your Lower Three Forks bench tests. If not, when might you have something more to share?

Yes, we're still very much in the early days of the Three Forks lower benches. We've had great success of course in the first bench. I believe we've quoted numbers that we have a little over 20% of our production is in fact coming from the Three Forks first bench. We have plans to initially focus in the Myrmidon area, and we've got about six wells currently planned for late 2014, early 2015. Permitting is currently in progress. The data we will get more in the near term is from some of our working interest participation and some OBO pilot projects. Those we talked about quite extensively at Howard Weil. We'll take that data and of course use it as we look at developing our own inventory on the operated side.

Okay, great. Thank you.

Thank you.

Thank you. Our last question comes from Ed Westlake of Credit Suisse.

Yes, just a follow-up. In the past you've given us some sort of instantaneous rates. I know they're not very helpful for the Eagle Ford, but just to give us a sense of actually seeing it in the numbers. Appreciate all the color you've given on wells to sale, but maybe some color on current production in the Eagle Ford?

What I would say, Ed, is that we remain on plan in the Eagle Ford to deliver our target for the year. We're at or above 100 KBED in the Eagle Ford. Again, because of the number of wells to sales in the first quarter, that dampened a bit the production for the first quarter. But we still had good growth quarter on quarter, 7%, even with that number of wells to sales. As I mentioned, with the pace that we're on for the remainder of the year, we feel very confident in our Eagle Ford growth rates for 2014.

Then this is in my opinion noise, but it's important for some folks. The 213 for the US production came in below the guidance that you gave in February. I appreciate that's only a month and a half of data. What do you think went wrong to drive the guidance below the bottom end of the range in the US?

Yes, I think we were pretty explicit on that one, Ed. I appreciate you raising it, which is we did have pretty significant weather impacts in North America -- not only on our current base production, but we had pretty dramatic impact on our ability to do our D&C activities in the Bakken. When you look at that in aggregate, it would absolutely have delivered us at the mid-point of the range. It was a bit of external impacts that were out with the asset team's control that impacted not only production, but activity levels as well.

A little bit more contingency in the winter months, I guess, going forward and hurricane season?

Yes. It's a little bit tough, because even though we're very accustomed to severe weather in the Bakken, this has been an anomalous winter, even by Bakken standards. Our inability really to run the frac crews, and even sometimes get to location, put a very large challenge on us in the Bakken.

Finally, just on the Austin Chalk of the Eagle Ford co-development, obviously you've put tight curves into the Howard Weil presentations, which reflect your geological view of where those wells will go. From the outside, you can get data off the Texas RRC, but that doesn't give days, down time. It just shows you what the actual production is from the wells. We're observing that the cumes on some of those wells are less than the cumes that you're seeing on Eagle Ford stuff that's close by. Maybe just a little bit of color on -- I mean is it just as you're testing the term, perhaps these wells aren't up as much as they would normally, in a full-development mode?

We certainly have not seen anything in the wells that we have bought on line that causes us concern relative to the type curves. We have quite a few of these wells now that have pretty extended days on production, some of them approaching 250 days and plus. We're very confident. We out-sourced some of the older Austin Chalk Upper Eagle Ford wells that have cumed quite well. Our confidence still remains quite high, Ed, in the areas where we've tested the Austin Chalk Upper Eagle Ford.

The fear people have is the decline rate because some of the earlier Austin Chalk tests in different parts of the Austin Chalk. I get that the shale is more like shale in your area, but had higher declines. That's why people look at it.

No, I understand. Also, I think people are also tainted a bit by their view of the more traditional Austin Chalk, as well. As we've stated, there are some fundamental technical aspects of the Austin Chalk Upper Eagle Ford in our acreage position that make it pretty unique. One, it's in direct contact with the Eagle Ford Reservoir. Two, it's got its own organic content, so it's somewhat self-sourcing. Coupling that with the well performance that we've seen, we're quite comfortable -- again, in the areas where we have cumulative production.

Thank you.

Thanks, Ed.

We have one final follow-up question from Jeffrey Campbell of Tuohy Brothers. You may go ahead.

Thank you. Going back to the Austin Chalk, I just wanted to ask you what was the reason for the rate restriction on the Children Westin Well?

On that point, Jeff, we are using our similar choke optimization process that we use across the field that we think balances present value versus ultimate EUR. We're very comfortable with our choke optimization process that we have in place. We want to ensure that we don't damage the reservoir for its long-term performance. Again, we feel very comfortable. We've got enough experience with the Lower Eagle Ford and the appropriate way to manage chokes that we are extending that process into these Austin Chalk Upper Eagle Ford wells.

Okay, that's fine. I really wanted -- I was familiar with your program. I just wanted to make sure that it was a voluntary choking, and not maybe something (inaudible - multiple speakers) --?

Oh no, absolutely. The 1660 force is our typical approach on choke optimization, and there's nothing more to read into that.

Okay, great. I wanted to ask you one other final question with regard to the Austin Chalk. What I'm really thinking of here is Slide 10 from your Howard Weil presentation, where you showed a selection of acreage, and you had some color dots that showed the different Austin Chalk vintages, and where they were drilling. Can you characterize just on a percentage basis what you see as the potential -- the percentage of acreage that's potentially prospective for the Austin Chalk? I don't know if you think you've got enough wells yet, but has some percentage of that prospective acreage been delineated by the drilling you've done to date? Thank you.

I would say we're still in that very early days. That map that you referred to was illustrating us walking around our acreage position from an appraisal standpoint. The positive is, as we talk about the next set of wells, bear in mind that we've got two Austin Chalk wells that are waiting on completion right now. We have three more pilot groups that have a total of six Austin Chalk wells in them that are currently drilling. What I'll share with you is that those tests will take us to the north and to the east, which will help us further delineate that acreage position. I think we'll have a lot of excellent data to share a bit later in the year, as we complete that pilot work. But we're staying with that plan as we described at Howard Weil.

Okay, great. Thank you.

Take you.

Thank you and that was our last question. I will now turn the back over to Mr. Chris Phillips for closing remarks.

Thank you, Tiffany. We appreciate the questions and interest in Marathon. If you have additional questions, please don't hesitate to call myself. We hope you have a wonderful day. Operator, thank you. This concludes today's conference call, and you may now disconnect.

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