馬拉松石油 (MRO) 2013 Q1 法說會逐字稿

Good morning and welcome to Marathon Oil Corporation's first quarter 2013 earnings webcast and conference call. The synchronized slides that accompany this call can be found on our Web site at Marathonoil.com. On the call today are Clarence Cazalot, Chairman, President, and CEO, and Janet Clark, Executive Vice President and CFO.

Slide 2 contains a discussion of forward-looking statements and other information included in this presentation. Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2012, and subsequent Forms 8-K, cautionary language identifying important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note that in the appendix to this presentation there is a reconciliation of quarterly net income to adjusted net income for the periods presented, as well as operating estimates and other data you may find useful.

Turning to Slide 3, beginning in 2013 we changed the Company's reportable segments to better reflect the growing importance of our US unconventional resource plays. All periods presented have been recast in this new segment view. There are still three reportable operating segments with each organized and managed based primarily on geographic location and the nature of its products and services. The three segments are North American E&P, which explores for, produces and markets liquid hydrocarbons and natural gas in North America and includes our in situ position in Canada; International E&P, which explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces in markets liquefied natural gas and methanol; and Oil Sands mining which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.

As discussed on Slide 4, we also changed the presentation of our consolidated statements of income primarily to present additional revenue and expense details and to report certain expenses more consistently with our peers. To effect these changes, certain reclassifications of previously reported amounts were made and as a result general and administrative expenses for the first and fourth quarters of 2012 increased by $39 million and $38 million respectively, offset by reductions in production, other operating and exploration expenses and taxes other than income. Full-year 2011 and 2012, along with second and third quarter 2012 data, will be added to future published documents.

Slide 5 provides an analysis of cash flows for the first quarter 2013. Operating cash flow before changes in working capital was $1.6 billion, a 40% increase over the fourth quarter as a result of higher sales volumes, lower production cost per BOE and better US liquids realizations, particularly for Bakken crude. Proceeds from dispositions of $312 million almost completely offset the debt repayments of $314 million. While working capital changes resulted in a $73 million use of cash and we paid dividends of $120 million. We ended the quarter with $768 million in cash, $84 million higher than year-end 2012 while total debt was $6.5 billion, bringing our net cash adjusted debt to capital ratio down slightly to 24%.

Slide 6 reconciles quarter-to-quarter adjusted net income. The first quarter 2013 was 7% lower than the fourth quarter 2012. Our North America E&P first quarter after tax earnings decreased $160 million, largely a result of a $218 million after tax unproved property impairment in the Eagle Ford. The first quarter 2013 effective tax rate was 73% or 65% excluding Libya.

Slide 7 shows the North America E&P segment's first quarter 2013 earnings decreased from income of $101 million in the fourth quarter 2012 to a loss of $59 million in the current quarter. Again, this loss was primarily the result of the unproved property impairments I just discussed. Lower natural gas prices and volumes driven by the disposition of the Company's assets in Alaska were more than offset by higher production from the lower 48 resource plays and stronger crude prices in the lower 48, again, particularly for the Bakken.

Slide 8 shows the changes driving our first quarter 2013 International E&P earnings. The segment income of $453 million in the first quarter was little changed from the $446 million recorded in the fourth quarter 2012. The first quarter saw an under lift in Libya, driving a negative volume variance which was offset by lower income taxes. Higher DD&A was seen in the quarter as a result of first sales from Angola which was offset by a positive variance in the other category as a result of higher earnings from our equity investments in EG and lower indirect costs because of employee bonus accruals in the fourth quarter 2012.

Slide 9 shows quarter over quarter data for LNG and methanol sales. LNG sales volumes were higher as a result of an additional lifting in the first quarter compared to the fourth quarter of 2012, while methanol sales volumes were down slightly over the same period.

Slide 10 shows our Oil Sands mining segment income increased $21 million sequentially primarily because of higher volumes driven by reliability improvements. Combined production from the Jackpine and Muskeg River mines set a record bitumen production rate in first quarter. In addition, the upgrader availability was 100% for the first quarter, allowing the facility to maximize production of lighter synthetic crudes which improved realizations and profit margins. This was partially offset by higher costs at the mine related to contract labor associated with seasonal activity. I'll now turn the call over to Clarence to discuss operations.

Good morning, everyone. Slide 11 summarizes the key highlights for the first quarter. We had strong production growth and cash flow from operations. Our available for sale production was up 4% over the prior quarter and up 19% over the first quarter of 2012 excluding Libya and Alaska. We continued our focus on controlling our cash cost and this, along with other factors, led to a 40% increase in cash flow from operations before working capital changes. We continued our solid execution in the US unconventional plays, particularly the Eagle Ford and the Bakken, and indeed increased our 2013 production guidance in the Bakken to 40,000 BOE per day net. We also increased our overall production guidance for 2013 for our worldwide operations to 7% to 10% growth over 2012 versus our prior guidance of 6% to 8%.

Moving to Slide 12, I'll comment on our execution on our key resource plays and future expectations. Eagle Ford first quarter production averaged 72,000 barrels of oil equivalent per day, a 22% increase over the prior quarter. The migration to pad drilling is ahead of schedule with 80% of wells drilled in the first quarter drilled off multi-well pads. Our 2013 target for drilling between 215 and 250 net wells remains unchanged. We are currently operating 16 rigs and we'll continue to monitor rig efficiency in order to hit our targeted annual well count. We've also begun testing the Austin Chalk and Pearsall formations within our acreage to assess their potential.

Production in the Bakken averaged 37,000 barrels of oil equivalent per day during the first quarter. The strong performance of our asset team has allowed us to once again raise the 2013 targeted annual production to approximately 40,000 barrels of oil equivalent per day. The targeted 2013 well count of between 65 to 70 net wells remains unchanged. Approximately 45% of our oil production was transported to market via rail in the first quarter. In the Oklahoma resource basin, our targeted 2013 well count of between 15 to 19 net wells remains unchanged. And during 2013 we will drill four wells to assess the potential resource within the Mississippian Lime and Granite Wash horizons.

Slide 13 shows our 2013 refocused and very active exploration drilling schedule. The program has already resulted in the successful appraisal of the outside operated Shenandoah prospect in the Gulf of Mexico during the first quarter. We are currently participating in eight exploration or appraisal wells and expect to evaluate the potential of this program over the next 12 months.

Slide 14 demonstrates that since the first quarter of 2012 our quarterly worldwide production available for sale, excluding Alaska and Libya, has grown approximately 18%. The growth wedge over this time was primarily driven by our lower 48 onshore production.

Slide 15 shows that our lower 48 onshore production available for sale has grown approximately 100,000 barrels of oil equivalent per day from the third quarter of 2011 to the first quarter 2013. Importantly, liquids volumes increased from 55% to 72% of total volumes over this same period. The 2013 first quarter production was 9% higher than the fourth quarter 2012. The target for fourth quarter production is between 190,000 and 210,000 barrels of oil equivalent per day which is an increase from the 185,000 to 205,000 BOE per day range we previously provided.

Slide 16 shows the historical available for sale and sales volumes for the North America and International E&P segments, including Libya and Alaska, since the first quarter of 2012. Production available for sale increased 16% and 2% over the first and fourth quarters of 2012 respectively. New production brought on stream in the first quarter of 2013 was partially offset by the sale of our Alaskan assets. Correspondingly, sales volumes in the first quarter were 15,000 barrels of oil equivalent lower compared to the fourth quarter 2012. However, if you exclude Libya and Alaska, sales volumes increased 19% and 4% compared to the first quarter and fourth quarter, respectively. At the end of the first quarter we had a cumulative under lift of approximately 3 million BOE. Of this, approximately 2.2 million BOE is natural gas in Libya. On the liquids side, we're under lifted 1 million barrels in Libya and 166,000 barrels in Norway. We are over lifted 273,000 barrels in the UK, 78,000 barrels in Angola and 64,000 barrels in EG. The first quarter saw our first liftings from Angola.

Slide 17 compares total company liquid hydrocarbon sales volumes excluding Libya for the first quarter of 2012, fourth quarter 2012 and first quarter 2013. Actual sales volumes grew approximately 27% between the first quarter 2012 and '13, with the US percentage growing from 34% in the first quarter 2012 to 42% in the first quarter of 2013. Slide 18 shows this same comparison for actual first quarter 2013 to estimated second quarter 2013 sales volumes. US sales continue to grow as a percentage of the total. Slide 19 shows our progress towards our stated goal of achieving a 5% to 7% compound average growth rate between 2010 and 2017. The impact of the growth being delivered by our onshore US plays is evident in this chart.

Slide 20 shows our International E&P quarterly cost structure per BOE. Our operated International production in Norway, Equatorial Guinea and the UK have maintained excellent reliability. DD&A per BOE in the first quarter 2013 was impacted by our first liftings from Angola. Slide 21 depicts the International E&P cost per barrel of oil equivalent trend without Libya. By excluding the low-cost Libya barrels, we see an increase in our overall cost per barrel compared to the prior slide. Slide 22 provides our estimate for the 2013 International E&P cost per barrel of oil equivalent and this excludes Libya. The forecast reflects a combination of the projected decline in our Norway production and the continued ramp-up of production from the non-operated Angola block 31 PSVM development. The higher operating cost per BOE also reflect the cost of turnarounds and work overs scheduled later in 2013.

As shown on Slide 23, total North American E&P cost per BOE increased quarter over quarter primarily because of higher exploration costs associated with the impairment of certain unproved leases in the Eagle Ford. But excluding the Eagle Ford impact, overall costs were lower than the fourth quarter and cash costs were lower by approximately $0.90 per BOE. Slide 24 provides the estimated 2013 operating cost per BOE for our overall North America E&P and the Eagle Ford. With that, I'll turn it back to Howard for the Q&A.

Thanks, Clarence. Before I turn it back to Brandon, I'd like to remind everyone to please limit yourself to two questions along with follow-ups, clarifications so we can get everyone in the queue and if we have time you can requeue for additional questions. With that, Brandon, we'll turn it over to you to open up the lines.

Thank you, sir.

(Operator Instructions)

Ed Westlake, Credit Suisse.

Congratulations on the progress in the Eagle Ford. Just diving into a bit of the detail, obviously we can all download data from the Texas Railroad Commission but one of the things you're doing is changing the completion design. I think you were operating certain frac spreads with an improved completion design and seeing some good results. As you look overall in the first quarter, can you give us some color of how many wells you completed were on the old design, how many are on the new design so that we can gauge your progress on IP rates against what you're doing in the wells and if there's any color on longer laterals as well that would be helpful.

Yes, Ed, this is Clarence. I don't have that kind of detail to give you today. We'll certainly look at including some of that color as we put together our future investor presentations. But I think as you recall, when we look at the investor presentations we've been showing, we've got a couple of slides in there that show the progress that we've seen particularly in the Excelsior, East Longhorn and South Barnhart areas comparing if you will our original completion designs to what we've seen of late. And of course we've seen, relative to the 30-day IP rates, anywhere from 33% to 75% improvement and then we give greater detail by quarter in Excelsior where we show the improvement in the 30-day IP's, again, where we've seen upwards of 75% improvement.

I think we'll continue to show that kind of improvement with our first quarter results and I also know, Ed, you had some questions about the state data perhaps not reflecting some of the higher rates that we've shown. We have to certainly look at and understand why the state data doesn't show certainly the results we're seeing, part of it we believe is that the data is reported on a lease level rather than a well level. But we certainly -- when we look at some of our more recent wells, we're seeing rates of anywhere from 2,000 BOE per day to 3,800 BOE per day of which liquids oil I should say ranging from 1,600 to 3,000 barrels a day. So really outstanding results reflective I think of the improvements we're making in our completion methods, but we'll look to provide some of that additional detail and color going forward.

Yes. Helpful color on those recent 24 hour IP's. Can you update us on the well costs as well that you're running because I think service costs are still a little bit coming down?

It is. And I think we are targeting a drilling and completion cost here in the second quarter of about $7.6 million per well and we see that trending down by the fourth quarter to about $7.2 million. On top of that drilling completion cost you have about $600,000 per well of facility cost. So we are seeing continued reduction in our cost. And -- but I think we've extracted pretty good efficiencies out of our operations, as well as cost improvements from some of our vendors.

Great. Thanks very much for the color there.

Doug Leggate, Bank of America.

Clarence, if I could maybe follow-up on Ed's question, over the last several quarters, we've had discussions backwards and forwards about not so much the completions but your operating philosophy as it relates to choke sizes and so on. And my understanding was you're going to be experimenting with that somewhat. I'm wondering if you can provide us an update as to whether or not you've decided to open these things up a little more aggressively in the early days?

Well again, I think the choke management, Doug, is one of the outcomes that we'll provide for guidance on when we're through with the pilot testing. The pilot testing, as you know, is both lateral spacing, vertical placement, and certainly completion methods to include choke size. So more detail to come on that. But I would simply say that I think we continue I would say to remain a bit on the conservative side at this point of not opening these wells up. And we continue to believe stress dependent permeability is an issue out here and we'd rather constrain the early flow rates and enhance recovery as opposed to opening the wells up and getting higher initial rates. So again, more detail to come on that I think as second half of the year we provide guidance on the results of the pilot program and what it really means if you will in terms of the wells that we'll drill, the resource and how we'll best complete these wells.

Got it. Thanks. My follow-up is somewhat unrelated. You reported the first region exploration results. I'm guessing that didn't quite come in as you expected. My question is, if normally exploration doesn't work, you've got obviously a big organization in Norway, what is the prognosis for Norway as a core asset for Marathon going forward? I'll leave it at that. Thanks.

I think as you recognized, we have said pretty clearly that 2013 will be the year that we begin to see the decline in our Norway producing assets. Again, the asset has outperformed our expectations in the first quarter. We'll continue to do what we can to maximize its recovery but pretty clearly, it is going into decline. Having said that, we continue to look for opportunities in and around Alpine to extend the life of this asset and we'll continue to do so. We are hopeful that the exploration we do here in the third quarter is successful, and that will give us an additional future development in Norway. But as you recognize, this is an asset that generates very significant cash flow for us, it's an asset that I think is pretty clearly misunderstood by the investment community.

I continue to see it referred to as low margin barrels, they're not low-margin either on an earnings basis and certainly not on a cash flow basis and it's a very high return asset. And so I think it is an essential part of our portfolio today, there will be a point in time obviously when it reaches a certain level of production that we would look to divest of it and perhaps put it in the hands of someone for whom it creates greater value. But at this point in time, Norway is a key producing asset and we believe it has upside.

Got it. Thanks, Clarence.

Pavel Molchanov, Raymond James.

Could ask one about Poland, obviously you're not the first US company to exit Poland but I'm curious, how many wells you've drilled and other analytical work you've done before making this decision?

Pavel, let me just check. I want to say offhand it's about 11 wells that we drilled. I'm sorry, seven. Six wells. Six wells that we drilled. And we've done some testing there. And I would simply say that we believe the results are fairly conclusive. These wells were drilled across the extent of our 11 concessions. And basically what we've found was thinner section than we anticipated and lower pressures, which for the most part high pressures are pretty important in these unconventional plays. And recognizing this was initial stage of exploration but costs are pretty high. And so we've come to a conclusion that while there may be some potential here ultimately it certainly doesn't fit our criteria. And as we've said, we are mobilizing to move out of our Poland concessions.

Okay. Appreciate that. Another one about in frontier opportunity you guys are pursuing in Kurdistan where you have had a fair amount of success already, what's the sequencing for moving into development mode on any of the blocks that you're currently working on?

Yes. We are in the process of preparing a plan of development on the non-operated Atrush block. That plan development will contemplate a development initially of around 12,000 barrels a day scaling up to a larger operation. And that's on the Atrush block that we now have a 15% interest in and in the Sarsan block, we are preparing for a declaration of commerciality on that non-operated block. We have been producing the initial discovery well there on an interim basis to see how the reservoir performs and look at the commercial elements of marketing those barrels, but those are the two existing discoveries, both non-operated at this point, that we are moving towards commercial development of. We are -- with our two operated wells drilling today at Mirawa and Safen, we're hopeful that we'll have our first operated discovery on our existing operated acreage. And we'll determine with success there, what's the best way to proceed to development.

All right. Appreciate the color.

(Operator Instructions)

Brandon, I don't know if it's the change -- do you have another question?

Yes we do. Eliot Javanmardi, Capital One.

Just curious if you could provide any color on the Three Forks and the Bakken, any progress you're seeing there in testing laws and also if you could talk a little bit about the well cost you're seeing out there? Thank you.

Yes. The well cost in the Bakken for us are about -- just to put on the same basis, I did the Eagle Ford -- they're running about $7.9 million drilling and completion. And an additional $800,000 for facilities and equipment. So about an $8.7 million well cost. And we'll continue to do what we can indeed to drive that further down. In terms of the Bakken and the Three Forks, we continue to develop those jointly. I think as we talked about we see very substantial potential in the Three Forks. That's been an upgrade to our overall resource assessment for the Bakken. In terms of current drilling activity, I don't have any numbers on that. We'll look to get back to you, Eliot, with any detail we can provide on that, but certainly we are continuing to evaluate the additional zones and the additional benches in the Three Forks.

Thank you. Appreciate that color. And also just as a follow-up, just get your macro perspective, Clarence, on the gas pricing in the US for '13 and '14 going forward just curious your thoughts there?

Well, our position has been one of a bit bearish. We continue to believe that the governor out there in terms of preventing gas prices from rising prices from rising too much is simply the degree of switching back to coal and I think as we saw gas prices get above $4 and begin to rise a bit, we saw coal come back into the mix pretty aggressively. And so once again, we see gas prices back down. So we remain rather bearish and rather conservative in our views about natural gas. We don't really see recovery to $5 or better until 2014 or beyond and obviously we put our money where our mouth is when you look at where we are spending our drilling dollars, we continue to focus on liquids in the US and North America in general and it's reflected in, as we said before, our lower 48 liquids production going from 55% to 72%. So we're well-positioned, we've got an opportunity set for natural gas, particularly in Oklahoma, we've got upside to Henry Hub prices in our EG, LNG business so we'd love to see gas prices go up. But at this point, our discretionary investment dollars are going to liquids, particularly crude and condensate.

Thank you.

Roger Read, Wells Fargo.

I apologize, I'm on a cell phone, if there's background noise. I wanted to ask quickly on the Eagle Ford shale, did you discuss at all or can you discuss at all the progress to date on the down spacing, what you've seen and any updates to this point?

Roger, we really have said consistently and said again today, you won't see the detailed results until the second half of this year in terms of us having enough production history and comparisons to actually then begin to come out, not just talk about the results but I think what you really want to hear is what are we going to do about it. How many wells are we going to go? How much resource do we expect to recover? What does the program look like for the next 10 or 12 years? That's information you'll see later this year.

I would say that we've come out now I believe in the press release and actually said we believe 80 acres is appropriate across the entire core area. So that is what we'll develop at the very least, including in the areas that we don't see down spacing potential. But again, we're increasingly drilling on 60 acre spacings now, beginning to move in that direction, and continuing to test 40 acres as well. So you'll see those results and hear the impacts of it later this year.

Okay. Thank you.

Ed Westlake, Credit Suisse.

This is more of a bigger picture question, could you maybe talk through where you are on potential disposals? Obviously, you gave a book loss for some of the Niobrara acreage which was non-core. I don't know what the cash value of that will be, but I'm more thinking the Oil Sands, any other assets around the portfolio?

Let me just say, Ed, I think the Niobrara we've talked about, but that will be a second quarter event so it was not in there and at this point, we are not able to talk about the cash side. Once the deal closes, we'll be able to disclose what the cash number is on that sale. In terms of to your point, our earlier comment that we were in discussions around a potential sale of a portion of our interest in AOSP, as I've indicated there, one way or the other we will tell you what happens there. If we don't have a deal we will let you know. And if we do, we'll let you know that as well.

So at this point, you can appreciate that discussions are still underway. And they're taking longer perhaps than we would have liked. It is our intent to bring this to a conclusion as quickly as possible. But again, it takes two to tango on this, and -- but we are still in those discussions. Outside of that, I think as we've said, we have closed transactions of $1.3 billion and we're confident of meeting our $1.5 billion to $3 billion target by the end of this year.

Thanks very much.

Doug Leggate, Bank of America.

I'm also taking advantage of the somewhat lightly attended call, Clarence, so apologies for the follow-up. Two if I may. Austin Chalk, Pearsall, can you give us any color as to what proportion of your acreage you believe might be potentially perspective? And when can we expect to hear a little bit more in terms of your expectations about drilling plan?

Starting with the Austin Chalk, Doug, it's still up in the air as to how much exact acreage we have. We believe it could be as much as 20,000 net acres, but that number is subject to change. To date we have drilled three wells in the Austin Chalk. We have one in progress. None of those have been fracked yet, so results yet to come. And in the Pearsall our view is that we have somewhere around 45,000 net acres in the Pearsall. We've drilled five wells to date, four of which were vertical delineation wells that we were able to better understand the reservoir. We've drilled one horizontal well and we will be fracking that well next week. So early days I think both on the Pearsall and the Austin Chalk but certainly we see upside in these reservoirs beyond what we have in the Eagle Ford here.

Thank you. My follow-up I don't know if Janet is on online this morning but my follow-up really is on cash flow. The cash flow this quarter looked particularly strong so I'm quite keen to see what's happening on the deferred tax line, particularly in the US. If you could help us with some of the moving parts as to why the cash flow was so strong this quarter I'm talking pre-working capital, Janet? Thanks.

I can tell you this is probably the first quarter where our deferred tax was actually a source of cash as opposed to use of cash, ie, the deferred tax in the US exceeded the negative deferred tax internationally. And, of course, we expect that to continue to see that to grow over time. As you know, because we are spending so heavily in the US, we're not paying cash taxes here. And typically our International taxes are primarily cash.

So [cash position is track for a] $6 billion plus type cash flow number, so any thoughts on use of surplus cash?

Doug, I think it's probably the same answer we give you every time we get that question which is, we look at the priority uses for cash is reinvesting in the business, if we have the opportunities on a value accretive way to do that and we can do it in a way that is cost efficient. Beyond that, you'll see us continue to look at our dividend. We think it's a very, very important part of the total shareholder return and make sure that we have a competitive and growing dividend to strengthen the balance sheet. And when we look at asset sales are chunkier cash inflows, that could potentially cause us to look at a stock buyback.

Great. Thank you.

I will now turn it back to Howard Thill for final remarks.

Thank you, Brandon, and thank everyone for your attention to our conference call. If you have any additional follow-ups, please let Chris or myself know. Have a great day. Thank you and goodbye.

This concludes today's conference. Thank you for joining. You may now disconnect.