馬拉松石油 (MRO) 2013 Q3 法說會逐字稿

Welcome to the Marathon Oil Corporation third-quarter 2013 conference call. My name is Christine, and I will be the operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded. I would now like to turn the call over to Mr. Howard Thill. You may begin.

Thank you, Christina, and good morning, everyone. I, too, would like to welcome you to the Marathon Oil Company third-quarter 2013 earnings webcast and teleconference.

On the call today with me are Lee Tillman, President and CEO; and JR Sult, Executive Vice President and CFO.

As a reminder, today's call is being recorded. And the call will include forward-looking information. As the prepared remarks were issued last night, I refer you to the forward-looking statement in that slide deck, along with our SEC filings, including our 10-K, 10-Qs and other filings which provide additional risk factors.

Before I turn the call over to Lee, I would like to remind you that when he opens the call to questions, to constrain yourself to two questions and then re-queue as time permits, so that we can get everyone's questions answered.

With that, I will turn the call over to Lee to summarize last night's remarks.

Well, good morning. Thank you, Howard. Let me add my welcome to the Marathon Oil Corporation third-quarter earnings call.

Before moving in to your questions, I wanted to begin with a few very brief opening comments. I just concluded my third month as President and CEO of Marathon Oil. And during this period, I have had the opportunity to visit many of our field locations, engage with a large cross-section of our dedicated employee base and dialogue directly with the investor and analyst community. I have also had strategic discussions with the Marathon Oil Board as we develop our near-term, medium-term and longer-term business plans.

Our December 11 Analyst Day will give the Marathon Oil leadership team an opportunity to share with you in more depth our next steps, as we strive to become the premier independent E&P Company. And will feature the business imperatives that will drive performance in 2014 and beyond. As such, it should not surprise participants on today's call if our responses to select questions are deferred until that time.

Our third-quarter results underscore our commitment to long-term shareholder value. Third-quarter net income is up over 30% from second quarter. And adjusted net income per share is up 30% quarter on quarter, at $0.87 per share.

Our resource plays continued to deliver strong volumes performance, with Eagle Ford third-quarter production double that of the same quarter one year ago. And we have high confidence in an Eagle Ford December exit rate of 100,000 oil equivalent barrels per day net, as supported by an end-of-October rate of approximately 92,000 oil equivalent barrels per day net.

Our renewed exploration portfolio with a bias toward emerging oil-prone plays that afford Marathon Oil the appropriate risk metrics, as well as the optionality to operate or monetize, is delivering on its promise, with announced discoveries in both Kurdistan and Gabon. In Gabon, we were also just awarded two prospective deepwater blocks, subject to successful contract negotiations.

We successfully completed the first phase of our $1 billion share repurchase program, and expect the second phase to commence in the fourth quarter. And as we look to our future, we expect our 2013 reserve replacement to be in excess of 140%, excluding acquisitions and divestitures. In summary, we remain well-placed to deliver on our commitment of 5% to 7% compound annual growth rate from 2012 to 2017.

I would now like to open the line for your questions.

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

(Operator Instructions)

Our first question comes from Edward Westlake from Credit Suisse. Please go ahead.

Yes, good morning and appreciate some of these questions you may want to stick to the Analyst Day. But just maybe some [follow-up to your statements].

We have heard from other companies of EUR recovery rates improving up in the Bakken, and also in certain areas of Eagle Ford. How do you see the EURs, say, particularly in the Eagle Ford. And then I will have a follow-up question on the Bakken trading against your expectations that you lay out in your presentation.

Good morning, Ed. Thanks for the question. Certainly we will get into a lot more granularity on the 11th of December. But I think, Ed, focusing on Eagle Ford, certainly what we see is our well completions are performing EUR-wise at or above the type curves that we have established in both the Eagle Ford, as well as the Bakken.

However, as you know, there is variability across all plays. So there are various type curves that we are comparing against. But overall, our performance is very well-aligned with the type curves that we've assumed in our go-forward volumes profile.

And then on the Bakken, you've got the slide from the Barclays conference, the 60,000 barrels a day in 2018 or so. Can you just remind us what is the spacing, say, in terms of terms of wells per [TSU] for the middle Bakken, and how much at Three Forks you assumed. Because your commentary [in retested about testing] the Three Forks. Thank you.

Yes, absolutely. Primarily, we continue to be on the 320-acre spacing in the Bakken, largely. However, we continue to run some high-density pilots where we look at combinations of both the middle Bakken, as well as the Eagle Ford -- or excuse me, as well as the Three Forks.

On the Three Forks though, what I would say, Ed, is that we have quite a bit of production already in the Three Forks first bench. As we look out in 2014 -- and again, we will talk more about this at the Analyst Day -- we are starting to also look at the additional benches in the Three Forks. But we are having very good success in the first bench.

Okay. Thanks for much

Thank you, Ed

Thank you. Our next question comes from Evan Calio from Morgan Stanley. Please go ahead.

Good morning, guys. First question is on 4Q guidance. I'm just trying to understand US volume guidance, modestly up Q on Q, I think it is. 152 to 162 versus 151.

In October you were 92 on the way to 100 by year end in the Eagle Ford. In the Bakken, 3Q was flat due to temporary shut-ins, due to adjacent well completions, which I presume would come back and drive some kind of increase, with Bakken, Eagle Ford looking better.

Is there something in the [gum] or other American volumes in that guidance? I'm just trying to square the circle. Your guidance looks conservative.

Well, I think, again, the guidance is meant to reflect our risk view of volumes going forward. Clearly it's reflecting our best estimates in the resource plays, recognizing that some of that will be offset by decline in the Gulf, as well as some of our other base assets in North America. So all that is really rolled into that number.

We still view that we are going to exit strongly in the Eagle Ford. We have talked about the 100,000 barrel oil per day exit rate in December. We are looking to be probably just under the 40,000 barrels per day guidance that we provided -- that's the Bakken as well.

Okay. So that's good then. Moving on to exploration. Interesting that you guys picked up the additional blocks in Gabon. Maybe two part question.

Where were they in relation to your other block? And on the Diaman specifically, do think you may have been drilling a gas cap when drilling operations ceased? Did the operator establish the bottom of the hydrocarbon column in that well? What else -- what do we know and what don't we know about the well?

Well, let me maybe first start with the two blocks in Gabon. We participated, of course, as you know, in the lease round in Gabon.

One of the blocks is actually contiguous with the Diaba Block. The other block is a bit further south and a bit more inboard. It's in slightly shallower water, in about 1,100 meters of water. Both blocks, in our view, are highly perspective pre-salt plays in Gabon.

Coming back to the actual Diaman-1B well. What I would say is that we are still in the data analysis phase. We are still getting back, if you will, fluid samples and fluid property data for the well. We really need -- this is a 2.2 million-acre block. We are just in the early days of understanding what we have in the block.

Our view is that we need to be out with an additional well, hopefully in the 2015 timeframe, to continue to really identify the resource potential. And hopefully also discover where we might have an oil column in the block.

Okay, fair enough. Thanks

Thank you

Thank you. Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead.

Hi. Good morning, Lee.

Good morning

You've got a quite long list of expiration success here, and I'd like to come back to that. But first, could you just talk a bit more about the expenses, the exploration expenses [Bingham] had [they were]? And maybe provide a little more detail on the, both the dry hole costs and the impairments? Thank you.

Yes, well, certainly on the exploration side, there were a couple of big contributors there. One was the Sverdrup dry hole in Norway, which was of course expensed in this quarter. That was on the order of about $60 million, in terms of dry hole expense.

In addition to that, we also expensed the Safen-1 well in Kurdistan. Those were really our two largest contributors to dry hole expense. The Safen-1 well was on the order of about $10 million or so.

Okay. And then the follow-up would be, firstly in Norway. Can you talk about your appetite to stay in that relatively mature high-tech space?

And also, could you expand a little bit more on the specifics of commercialization of Kurdistan? I know that you've given some detail here about the production facilities you are putting in. Could you just clarify where that oil is going to go and be sold? Thanks.

Yes, well, let me start with Norway. Clearly the Sverdrup well provided us further input in terms of our go-forward strategy in Norway. That's part of the strategic internal discussions that we continue to have as we continue to look at our portfolio and ensure that we have the right portfolio mix. But I'm not going to get into any more specifics on an asset-by-asset basis relative to that.

Norway, as you've seen, continues to perform strongly. We just completed a turnaround in Norway on schedule and on budget. We are back up, of course, after that shut-down, and running at a high reliability rate in Norway.

Relative to the Kurdistan and a path to profitability, clearly we started in Kurdistan with four blocks -- two operated, two non operated. We now have discoveries on three blocks, and essentially a field development plan filed and approved in one of those three. That's the Atrush non operated block.

As you stated, that field development plan essentially has us drilling three wells, producing those back to a 30-KBD facility, and then moving those barrels ultimately to export or use internally. I would say from a destination standpoint, that is still yet to be determined. We are still in the very early days.

We just got the approval of the field development plan. So we will continue to work there with the operator, Taqa, on how we will ultimately market the crude that we produce there.

Thanks. See you in December. Thank you

Yes, absolutely. Thank you

Thank you. Our next question comes from Blake Fernandez from Howard Weil.

Guys, good morning. My first question was on the reserve. And I was hoping you could maybe give us some color around the regions or the areas where the bulk of those adds came. Specifically what I'm trying to dig around on is Eagle Ford. I wonder if there could be an impact of DD&A coming down in the next year as you book more reserves there. Thanks

Yes, well, certainly we will have a lot more color on reserve adds as we complete our year-end processes on reserve booking. But clearly the resource plays will have an element of those adds.

And you rightly state, as we continue to migrate to reserves in the Eagle Ford and to the proved category, it will have a net effect of reducing our DD&A rate. So that certainly is an objective that we have.

Okay. The second question I had for you was on buybacks. It looks like you're going to commence the second tranche in the fourth quarter. I'm just trying to see how we should think about moving into 2014. Is there any appetite to extend the program? [I don't even want to call] will that fully exhaust your authorization?

Well, no, it won't fully exhaust our authorization. We will still have authorization under the original Board authorization. It is our intent, of course, to complete the second half of the buyback, as you are aware from our release.

We completed the first half, the 14 million shares. The second half we would certainly link to driving toward financial close on Angola Block 31, which we still anticipate to be toward the end of the year.

In terms of how we view repurchase moving forward, I view it as a capital allocation decision. It will -- first and foremost, we look to invest organically in our business. And that's certainly what will be talking about at the December 11 Analyst Meeting. Then we will consider things.

We certainly look hard at our dividend, wanting that to be predictable in the future. Stock repurchases is certainly a lever that we have. But I view it as more of an opportunistic lever that we may use in the future. And then finally, we also have the option, of course, to strengthen our balance sheet.

Okay. Thank you, Lee. Appreciate it.

You bet.

Thank you. Our next question comes from Doug Leggate from Bank of America. Please go ahead.

Thanks. Good morning, Lee. I have a couple, if I may. First of all, in Norway the dry hole cost that you mentioned there. So my understanding is that exploration is key to further -- or [Alvheim] success, rather, is key to whether Norway remains a long-term core part of the portfolio.

You have obviously only been there a few months. But can you just try to give us an early feel as to how you feel about that core asset, given the high decline that you're facing there? And I've got a follow-up, please.

Okay. Well, certainly, expiration is an element of, I would say, our go-forward plan in Norway. No question. The performance of Alvheim asset is also a key element there.

As you are well aware, Doug, we continue to invest profitably in the Alvheim asset. We have in-field development drilling, as well as a pretty significant subsea tie-back that will be moving into the installation phase in 2014, with expected first oil in 2015.

So we continue to work the asset very hard. And it's a very high income-per-barrel asset for us. Very strong free cash flows.

But all of this information is factoring into our continual look at our overall portfolio, Doug. And again, I won't get into specifics on Norway. But suffice to say that we continue to scrutinize all of our assets there.

There are no sacred assets in our portfolio. We are going to be driven by profitability and ensuring they are accretive to the overall return to shareholder.

Thank you. (multiple speakers) Yes, thanks for that. My follow-up is, if you look at your exploration program, generally, you have inherited a program which is similarly disproportionately levered to the frontier areas of Kurdistan.

Can you help us with what confidence you have, as to whether Kurdistan can actually get monetized in terms of constance in exports, constance in the political backdrop -- basically, confidence in getting paid? I will leave it at that. Thanks.

Well, maybe starting first at a bit of a high level, Doug. Our exploration program is now, I believe, very well-focused in four basins that have some very common attributes.

One, they are either emerging or demonstrated plays. They're extremely oil-prone. And in the exploration space, I would say, they have a risk profile that we can tolerate.

And those four areas are, of course, Kurdistan, East Africa Rift, Gabon and the Gulf of Mexico. Each of those have their unique risks, both above ground, as well as below ground, that will ultimately factor into our decision on the best approach to monetize.

Do we develop and operate, or do we look for other avenues to monetize? I would say in Kurdistan, we are still in the very early days. We just had the first field development plan approved.

So the process is working there. We've had discoveries. It is certainly a high-quality hydrocarbon product. And we have a ministry there that we have a very strong and good working relationship with.

So I would just say, stay tuned. It's a work in progress. And is still very early days.

All right. Thanks, Lee

Thanks, Doug.

Thank you. Our next question comes from Jason Gammel from Macquarie. Please go ahead.

Yes, thank you. For my first question, I'll stick with exploration. And I just wanted to ask about Madagascar. Have you discussed any terms you might have received on the farm-out? Are you being carried for any portion of the well, et cetera? And if the well is successful, can you talk about the running room that you having in the Norphlet trend?

Yes. Well, certainly we are very excited about the Madagascar well. It is a Norphlet well, which is a little bit different than a lot of the paleo [maya plya] that you see in the Gulf of Mexico.

It's still a very challenging area, very deep water, greater than 8,000 feet. 25,000-foot well depth. So still challenging conditions. But very perspective.

In terms of the farm-out, without getting into any of the confidential details, I will say that there is a carry involved in that interest. Not only do I think we have running room in Madagascar, but certainly with success there, I think you will see us very quickly move toward appraisal in that area. And with success, we will also be looking to expand the position potentially in the Norphlet, based on acres that may be available.

So it's an exciting prospect. We still anticipate -- even though we, of course, had a little bit of a hiccup with the tropical storm moving through, we would still anticipate TDing the Madagascar well before the end of the year.

Okay, great. We will keep an eye out for that one. And then just one more, if I could please. And this may be something that just needs to be deferred.

But do you feel that you have enough of a representative sample in the Eagle Ford wells now, that the product mix that you had in the third quarter between oil NGL and gas is going to be representative of your production profile moving forward?

Well, certainly that's a moving target. As the mix of wells change as we move from the condensate window to the high [GO] or oil window, those proportions can change. But the ZIP code that we are in, which is something on the order of 70% or greater of liquids, those are -- that is our current target. And we would like to continue to stay in the liquids-prone area of the play, just because those, in fact, are our best and highest return wells.

And any comment on the NGO relative to crude oil split there?

Well, we are still running, I believe, around 60% or so on crude. And again, I think that's a statistic that we see carrying forward in 2014.

We will still see some shift in 2014 in inventory as we look at the mix. And what we will try to do at the December 11 meeting is give you a little bit better feel for what those 2014 profiles will look like.

Okay, perfect. I will leave it at that.

Okay. Thank you, Jason.

Thank you. Our next question comes from Roger Read from Wells Fargo. Please go ahead.

Good morning.

Good morning, Roger.

In the risk of asking something that will be addressed early next month, I'm just going to ask about some of the operating cost reductions you've achieved in the Eagle Ford and the Bakken. What has been the -- I understand the year over year -- you know, down about 20% each.

But what has been the recent trend? Are we seeing that flatten?

As a result of maybe some of the changes in the completion jobs, you're getting a better EUR, but not necessarily lower costs on an aggregate or an absolute basis. But you are on a per unit basis. Can you help us out a little bit with that?

Absolutely. And for clarity, you said operating cost, but I think you're talking about capital costs here. And capital --

Capital costs, yes.

Yes, I understand. I completely understand the question. On the capital efficiency side, we continue to drive our drilling times down, as noted in the press release.

The Eagle Ford now we have down to spread-to-TD of about 12 days. We are continuing also to work completion optimization, not just from a cost standpoint, but also from a value standpoint, and ensuring that we deliver the highest productivity completions to generate the best economics.

We also are seeing commercial leverage, as well, in the Eagle Ford. As we look forward to 2014, begin looking commercially at our frac crews, et cetera, we still see room there to drive some of that commercial element down a bit lower, as well.

I believe I mentioned at Barclays that some of our best wells in the third quarter we were drilling for around $7.3 million total D&C. On average, we are drilling them at about $7.8 million in the Eagle Ford.

As we move out in 2014, we would like to see, again, those analog best wells be down around $7 million. As we are able to continue to exercise some of this optimization on the D&C technical side, but also take advantage of some of the commercial leverage that we think exists in the play today.

Okay, thanks. And then the unrelated follow-up. The OSM turned in a pretty good quarter. We all know it's been erratic at times.

Can you give us maybe some idea of -- were there good things that occurred in the third quarter? I recognize your guidance for the fourth is for fairly flat. But have we turned some sort of a corner here? Or as you look to 2014, it's going to be erratic, it's going to be seasonal, and we just have to live with that?

Yes. Well, certainly you are correct in that we have been up and down in oil sands mining. The third quarter really reflected good performance by the operator from a reliability standpoint. But then we got quite a bit of help on the realization side, as well. Those two factors -- volumes and realizations -- really drove the outstanding performance from oil sands mining.

As we talked in previous teleconferences, we continue to work with the operator at OSM to try to drive the reliability higher, drive the reliability to be more predictable. But I will tell you that, that remains a work in progress.

As we look out in fourth quarter, we recognize that we will likely have some pretty significant plan downtime looking out ahead, which could impact us. But we provided some guidance around our fourth quarter view, and that's certainly reflected in that guidance.

But it's a challenging asset. Reliability continues to be our number one challenge as we look at oil sands mining.

Thank you.

You bet.

Thank you.

(Operator Instructions)

We have a question from Pavel Molchanov from Raymond Jones. Please go ahead.

Hi, guys, thanks very much. So Libya has, to no one's surprise, been a complete black box lately. And I would ask if your thinking about keeping that asset has been evolving at all, and if so, what might get you over the hump to put it up for sale?

Well, Libya, again, is an asset in our portfolio, just like the remainder of our assets, that gets scrutinized for the value that it delivers within the portfolio. Libya right now -- unfortunately, we are experiencing the above-ground risk, the labor strikes there that are impacting our terminal. We haven't really done any lifting there in the last two months of the quarter. So clearly, it's been a downward pull on our volumes.

We recognize the above-ground risk there. But you also have to recognize that Libya has an extremely strong subsurface asset. It's a world-class asset. It does have growth potential going forward. Clearly some challenging fiscal terms there. But a world-class resource.

In terms of looking at next steps in Libya, from our perspective, we are hopeful that the sovereign authority will be able to rectify the current impasse on the labor strikes and get us back online. And that's our number one objective today.

Okay. And then just a quick follow-up on Kurdistan. So obviously, you guys have a plan of development now for one of those blocks, following the Mirawa discovery. How close are you to getting a plan of development for that block?

Well, as you know, on that particular block, Mirawa was a strong discovery for us. But we feel compelled now to move over and drill an analog structure, which is the Jisik-1 well. That will give us a much broader data set to come up with a realistic field development plan potentially in the future. But I would say today, we are still in the discovery and appraisal mode for that particular block.

Okay. So 2014 realistic to get a plan, or too early?

No, I would just say we are going to -- we will base that timeline on the data that we get from the wells. Depending on what we see at Jisik will likely drive us one direction or another. So we really need to wait and see the results, combine that with the Mirawa-1 result, and then that will start helping us set the timeline.

Okay. Thanks, guys.

Thanks, Pavel.

Thank you. I would now like to turn the call back to Howard Thill. Please conclude.

Thank you, Christina. And as Lee said, the December 11 meeting is coming up quickly upon us. If you have not signed up for that, please send either Paul or myself or Chris a note so we can get you signed up for that Analyst Meeting.

Other than that, this concludes our call. We appreciate your interest in Marathon Oil. Have a great day.

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