馬拉松石油 (MRO) 2012 Q4 法說會逐字稿

Good afternoon and welcome to Marathon Oil Corporation's fourth-quarter 2012 earnings webcast and conference call. The synchronized slides that accompany this call can be found on our website 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, 2011 and subsequent Forms 10-Q and 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 in the appendix to this presentation there is a reconciliation of quarterly net income to adjusted net income for 2011 and 2012, first-quarter and full-year 2013 operating estimates and other data that you may find useful. We'll now move to slide 3 and I'll turn the call over to Clarence Cazalot to review 2012 operational results.

Thank you, Howard, and good afternoon. 2012 was a very successful year for Marathon, characterized by strong operating results that met and in several cases exceeded our targets. As shown on slide 3, since the beginning of 2010, our quarterly E&P production available for sale has grown approximately 32%. This growth excludes Libya, because of the civil unrest there in 2011. You'll especially note the growth over the past two quarters, which was driven by our lower 48 on-shore production.

Slide 4 demonstrates the more than doubling of our lower 48 on-shore production from the third quarter 2011 to the fourth quarter 2012. The 2012 third to fourth quarter growth alone was 17%. Importantly, liquids volumes increased from 55% to 70% of total volumes from the third quarter of 2011 to the fourth quarter of 2012, with a preference to oil and condensate.

We estimate reaching between 165,000 and 175,000 barrels of oil equivalent per day in the first quarter 2013, and we've again set a forward target with fourth-quarter production expected to be between 185,000 and 205,000 barrels of oil equivalent per day.

Slide 5 shows that our liquid hydrocarbon sales volumes for E&P and Oil Sands Mining, excluding Libya, increased 6% from 297,000 barrels per day in the third quarter to 313,000 barrels per day in the fourth quarter. Again this increase was driven by the US resource plays, particularly the Eagle Ford, as well as higher sales volumes in the UK offset by lower EG volumes. You will note that US sales volumes have increased from 37% of the total in the third quarter of 2012 to 42% in the fourth quarter of 2012.

Slide 6 shows this same comparison for actual fourth-quarter 2012 to estimated first-quarter 2013 sales volumes. The US sales volumes are expected to continue to grow as a percentage of the total. You'll also note that we expect to take our first liftings from Angola in the first quarter.

Slide 7 shows our international E&P cost structure per BOE by category over the past eight quarters. Our operated international production in Norway, Equatorial Guinea and the UK have maintained excellent reliability, and this effort is not only reflected in our production levels but also in maintaining our cost structure over the last two quarters.

Slide 8, which excludes Libya, shows that as we enter 2013, we anticipate increases to the international cost structure. This is a combination of the projected decline in our Norway production, and as I just mentioned, the start of production from the non-operated Angola Block 31 PSVM development. While we were seeing some increase here, I would point out that our overall international costs per BOE are still quite low.

As shown on slide 9, total US E&P cost per BOE increased quarter over quarter, primarily because of higher DD&A rates in the growing Eagle Ford and higher exploration expenses in the Gulf of Mexico. Slide 10 compares the actual 2012 and estimated 2013 operating cost per BOE for US E&P in the Eagle Ford. Importantly, you will note that our cash costs, field level controllable and other, are decreasing on a BOE basis, reflecting our growing domestic production.

However, US DD&A levels are increasing on a per BOE basis, largely as a result of a higher DD&A rate for Eagle Ford barrels, which are increasing from about 18% of our US production in 2012 to about 40% in 2013. In the Eagle Ford, as in most developing growth plays, DD&A rates in the early years are higher because initial reserve bookings do not reflect full-life EURs and these rates come down as performance justifies additional reserve bookings.

Moving to slide 11, I'll take just a moment to comment on our execution in our three key resource plays, beginning with the Eagle Ford, where we have 230,000 net acres in the core part of that play. As you know, we exited 2012 at over 65,000 net BOE per day, which is in line with what we had committed. And we've averaged 70,000 BOE per day in January. We've increased our 2013 target from 70,000 net BOE per day to 85,000 net BOE per day.

We're currently running 18 rigs and 5 frac crews in the Eagle Ford and we continue to improve our spud-to-spud times and averaged 19 days in January. We'll continue to see those spud-to-spud times decline, particularly as we execute about 70% of our drilling in the Eagle Ford in 2013 on multi-well pads.

We believe this may allow us to decrease ultimately to 16 rigs and still drill the roughly 290 plus wells that we planned for 2013. We have our nine pilots under way and, as we've said previously, we'll be commenting on the results of those pilots and certainly the impacts on our forward plans in the second half of the year.

As we turn to the Bakken, where we have 410,000 net acres. We're currently producing about 33,000 net BOE per day. We have five rigs and two frac crews active and we'll drill 65 to 70 net wells in 2013. Importantly, you'll recall that we increased our 2013 target from about 30,000 net BOE per day to 33,000 and now with the strong performance we've seen in the fourth quarter and in January, we're looking to increase our target for 2013 to greater than 35,000 net BOE per day.

Turning to Oklahoma, our resource basins there where we have about 220,000 net acres, we're currently producing about 12,000 net BOE per day from the Anadarko Woodford. We have two rigs operating in the Knox area of the Woodford and we'll have those two rigs active throughout 2013. As we've discussed before, we have a very significant resource base that we'll act upon in this area as we see improvement in both NGL and natural gas prices. And with that, I'll turn it back to Howard for the financial remarks.

Thanks, Clarence. Slide 12 provides an analysis of 2012 cash flows. Operating cash flow before changes in working capital was $4.5 billion, compared to $4.9 billion in 2011. Working capital changes resulted in a $437 million use of cash giving an operating cash flow of $4 billion for 2012, compared to $5.4 billion in 2011.

The decrease in operating cash flow year over year was primarily the result of working capital changes related to the 2012 ramp-up of operations in the Eagle Ford shale and Libya and the timing of tax payments. I won't step through each of the other cash flow items but just point out we ended the year with $684 million in cash, total debt of $6.9 billion, and a net debt to total capital ratio of 25%, the same as at the end of the third quarter.

Moving to slide 13, our fourth-quarter 2012 adjusted net income of $388 million was a 15% decrease over the third quarter 2012. Our international E&P fourth-quarter pre-tax earnings increased $119 million, while Oil Sands Mining, US E&P, and Integrated Gas saw offsetting decreases. Because of the higher percentage of international pre-tax earnings, we also saw an increase in income taxes.

As shown on slide 14, the E&P segment's fourth-quarter earnings increased slightly to $501 million. The increase was primarily driven by higher liquid hydrocarbon sales volumes and higher natural gas realizations, mostly offset by higher DD&A and operating costs associated with those additional volumes and higher exploration expenses.

Slide 15 shows the changes driving our fourth-quarter US E&P earnings. Large volume increases in the Eagle Ford and Bakken were partially offset by higher DD&A, operating costs and production taxes attributable to the new wells brought to sales. The increased exploration expense was associated with the unsuccessful Innsbruck well in the Gulf of Mexico.

Slide 16 shows the impact on international E&P earnings from the higher liquid hydrocarbon sales volumes, price realizations and lower DD&A partially offset by higher other costs and income taxes. During the fourth quarter, we over-lifted in Libya, which has a favorable DD&A rate per BOE compared to the volumes we lifted in the third quarter, but is also reflected in the higher income taxes shown on this slide.

As shown on slide 17, quarter over quarter our E&P segment production available for sale was essentially flat while our US resource plays continued to ramp up significantly. There was an offsetting decrease quarter over quarter in Libya. As you may recall, we signed a gas sales contract during the third quarter in Libya and recorded all previous volumes available for sale in that quarter. Excluding Libya, our production of available for sale increased 7% quarter over quarter.

Sales volumes increased approximately 8% as a result of over-lifting volumes in Libya and in the UK. At the end of the fourth quarter, we were under-lifted by approximately 4.7 million BOE, of which approximately 4.1 million BOE was natural gas, 2.4 million in Libya and 1.7 million in Alaska gas storage.

On the liquids side, we were under-lifted 160,000 barrels in Angola where we had first production from our PSVM development in Block 31 during the fourth quarter, as Clarence previously mentioned. We were also under-lifted 180,000 barrels in Europe, 145,000 barrels in EG, and 100,000 barrels l in Libya. During the fourth quarter, we significantly reduced our liquids under-lift in Libya by a 1.9 million barrel over-lift in the fourth quarter.

Slide 18 shows our Oil Sands Mining segment income decreased $46 million sequentially. This was a result of unplanned down time at the upgrader in the fourth quarter 2012, resulting in lower production volumes and lower price realizations. Net synthetic crude oil sales decreased 9% from 53,000 barrels per day in the third quarter to 48,000 barrels per day in the fourth quarter.

Moving to slide 19, Integrated Gas segment income decreased $4 million quarter over quarter to $35 million. This was primarily a result of lower LNG volumes with 14 liftings in the fourth quarter compared to 16 in the third quarter. Higher methanol sales partially offset the lower LNG income. We'll now move to slide 20 and I'll turn the call back to Clarence.

Thanks, Howard. Further to Howard's explanation of cash flows, I want to reiterate our commitment to living within our cash flows while we grow our net production at a compound average rate of 5% to 7% from 2010 through 2017.

In 2013 alone, we promise growth of 6% to 8%, excluding Libya and asset divestitures, and as some of you have noted already our production guidance for 2013 puts that range at 6% to 13%. That represents a stretch target. I'll simply reiterate our commitment is 6% to 8% growth and this is backed up by drilling inventory that we have great confidence in, as I discussed earlier.

Moving to slide 21. This strong growth profile is underpinned by a growing reserve base. About this time last year we promised greater than 150% reserve replacement for 2012. I'm very pleased that our team has exceeded that expectation, delivering 185% reserve replacement, excluding acquisitions and divestitures, at preliminary F&D costs estimated to be $17 per BOE.

Including acquisitions, which strengthened our Eagle Ford position, we replaced 226% of our 2012 production, again at an F&D projected to be approximately $17 per BOE. Over a three-year period, which we've stressed is a more representative measure, our average reserve replacement has been 173%, and we've done this at a preliminary F&D rate of $23 per BOE.

This has led to the highest level of proved reserves for Marathon Oil in 40 years, and we're not finished. We have a portfolio that includes significant untapped resource and through continued execution of our strategy we plan to continue growing significant shareholder value.

Slide 22 summarizes many of the points I've just made, so I'll just touch on a couple of additional key priorities for 2013. First is drilling a high-graded exploration program that we believe provides significant upside to our shareholders. Second, our drive to continue to enhance our value through portfolio management and an increased focus on enhancing margins and overall cost competitiveness. And with that, we'll open the call to questions.

To accommodate all of those who want to ask questions, we ask that you limit yourself to two questions and you can reprompt for additional questions as time permits. Christine, with that, I'll turn it over to you to get people in the queue.

Thank you.

(Operator Instructions)

Doug Leggate, Bank of America.

Thanks. Good afternoon everybody. I understand the operating cost guidance, Clarence, thanks for that. I guess my question is really on the -- as you shift your production drills towards the US, can you help us understand what the cash tax impact is in terms of how we should think about the fair taxes going forwards? And I have a follow up, please.

Let me let -- Doug, I'll have Janet touch on that.

I think because of our very high capital program in the US, the domestic spending is such that we would not expect to see cash taxes paid in the US in the coming year. As you know, our international taxes are largely all cash and, in fact, deferred tax is reversing on us and is incremental cash.

Okay. The reason I asked the question, Clarence, back to you, if I may, is that based on your current capital program, at least given your production outlook, it seems to us that you're going to be throwing off a fair amount of cash, an update perhaps possibly on how your sales process in Canada is going as well. But when you take that together it looks like you're going to have a fair amount of cash this year, just curious as to what your priority for using that cash is? And, I'll leave it there, thanks.

Well, Doug, first of all, I'd say the amount of cash we throw off obviously is going to be dependent upon the commodity price environment that we face. But there's no question that certainly the growth in our US production is going to drive strong cash flows from those resource plays. At the same time you would recognize we are seeing declines in some of our legacy assets that have also been historically very strong cash flow providers, like Norway. As you know, we will see about a 20,000 BOE a day decline in Norway this year from about 90,000 BOE a day to 70,000 BOE a day, as well as the Gulf of Mexico. So again, obviously we do expect to continue to grow our cash flows both on an absolute and per share basis. I think you just have to look at all the elements that come to bear on that.

With respect to -- you mentioned Canada. I would simply say that, as you know and many others know, we did indicate that there had been discussions around the potential sale of a portion of our interest there. I think what I would say to everyone is, when and if that is no longer relevant or correct, we will say something. So you'll hear something either way, either in terms that we have come to a mutually acceptable transaction at some point in time or indeed, if indeed, those discussions should break down, we would so advise of that as well.

The other sales, again, outside of Canada, we have said $1.5 billion to $3 billion of transactions between 2011 and the end of 2013. We continue to make progress on that and you will have noted in our Earnings Release today that we did announce the sale of our 34% interest in Neptune Gas Plant for $170 million. We continue to make progress towards our overall goal by the end of this year.

Really trying to get to the use of cash, Clarence, as opposed to the sources of cash. I guess, I'll get to the punch line, are you happy with the portfolio or do you feel you have enough debts? Or should we expect additions to the portfolio as we go forward?

No, I think, coming back, Doug, we have said, first of all, we're going to spend within our cash flows. And certainly the $5.2 billion CapEx program we've outlined for 2013, we think fits with that. It is straight down the fairway of the guidance we've given of $5 billion to $5.5 billion of spending going forward. With respect to additional cash that may come in from asset sales, we certainly will look at that. I think we've indicated in the past that for the most part we believe that the bolt-on acquisition programs that we've been doing, particularly in the Eagle Ford, have largely reached their end. We believe we pretty much, with maybe one exception, exhausted that opportunity set.

Having spent quite a bit on acquiring and building the resource base we have, we will now set about to spend our money developing that. Additional cash, we would look to either. As we've said, potentially a share buyback, strengthening our balance sheet and increasing the dividend and no one should read into that necessarily that, that's a priority. We'll assess that at the time. But clearly, returning value back to our shareholders is a key driver for us and certainly that's what we would look to do at that time.

Great. Thanks very much.

Paul Sankey, Deutsche Bank.

Hello, everyone. You outperformed again in the Eagle Ford. Could you talk a little bit more about how far -- really, what's driving that performance and particularly we're looking at the drilling days -- has exceeded our expectations in terms of how low you're going. How much further can you go with that, Clarence? Could you talk a little bit more about how much pad drilling you're doing, just fill us in more on just what's driving your success there? Thanks.

Well, you know, it's a real easy answer, Paul. It's extraordinary people. The team we have is doing an outstanding job across the Company. But certainly in the Eagle Ford as we drilled that many wells and continued to incrementally improve what we do, it all cumulatively adds up to very significant savings in spud-to-spud times. Of course, as I indicated in my remarks, we'll be aided in that in 2013 by the fact that we're moving to about 70% of our wells being drilled on multi-well pads versus very few pad wells in 2012. And as we've indicated in the past, pad drilling significantly accelerates the spud-to-spud times.

It's not necessarily representative of everything we've been able to do, but we've had occasions where three wells off one pad took us a total of 39 days, so roughly 13 days a well. Again, as you see more pad drilling, we're going to bring the average in January of 19 down to a much lower level. As we talked about driving down our overall cost in the Eagle Ford, it's a combination of savings on rig time as well as savings that we're realizing in our completion costs that's allowing us to drive our overall drilling and completion cost down below the $8 million level that we've talked about before. So, I think it's all of those factors, quite frankly, Paul, that continue to enhance our overall performance.

Great. Thanks. And I know you only want me to ask one follow-up. If I could jump across on the subject of people, there was an abrupt resignation in the past quarter that surprised us, Clarence. What is your public statement on what happened there? Thank you.

Yes, Paul -- and look, I know it came as a surprise and I know what you're referring to is Dave's resignation from the Company. I think as the release said it was to pursue other interests and obviously we wish Dave well in whatever he elects to pursue.

The message I would have for investors is that we have a very strong team here at Marathon. As I was just talking about the results in the Eagle Ford, we can say the same across the rest of our Business. We have a very talented, experienced leadership team and I believe the Company is in very, very good hands. I would simply say that the development of our leadership team, of our executives and succession plans are at very high priority at Marathon for the Management team and for the Board as well. And so again, I would reassure investors that the Company is in very good hands.

Thanks, Clarence. If I could just confirm that Marathon has a mandatory 65 year-old retirement age, without wanting to embarrass you I think is going to fairly shortly affect you.

Yes, actually, I'm 62, Paul, but I feel 52 on some days. (laughter) But to your point, it's what I was referring to just a moment ago. Succession planning is a critical priority in this Company. It is something that, particularly with respect to CEO succession, that the Board spends a great deal of time and effort on. I, again, will assure you as all the shareholders that when it's time for me to step aside, this Company will be in very good hands and will be ably led into the future. Again, I would simply say there's nothing for investors to worry about that point.

Thanks very much indeed, Clarence.

Evan Calio, Morgan Stanley.

Good afternoon, guys. Question on the Eagle Ford. You guys planned to drill 275 to 320 operated wells. I know you didn't bring as much to sales as you drilled in 2012 which is as expected. But how should we think about the backlog for 2013, building? Falling? Same ratio as it affects production? And then secondly, appreciate your color on increased pad drilling, but can you update me where you are on well cost today versus your 2013 target? Thanks.

I think, Evan, I'm not exactly sure which backlog you're talking about. You've cited the range we've given. I think a more specific number is about 290 to 295 wells that we plan to drill this year. We've talked about the fact that while we're at 18 rigs currently, we may be able to go to 16 rigs and still achieve that program. Beginning to feel pretty confident about that. We've been asked why don't you keep 18 rigs and drill more wells. I think it goes exactly to your question. We are drilling at a pace and growing our production at a pace that aligns with the midstream development and the take-away capacity, so we avoid just that backlog that you're talking about. And continue to be able to hook up our wells within a very short time of when we've got them fracked, so that we don't have a great deal of production shut in.

It has helped a great deal, as you know, that we have invested significantly in the midstream, last year was around $350 million. This year, it's about $190 million at central batteries and gathering lines. That has allowed us to move off of trucks with about 60% of our barrels now on pipe. That gives us, again, greater optionality and lowers our cost. Obviously is a CSR advantage as well in the region in terms of traffic. We intend to move that closer to 70% by the end of the year, so continuing to move our barrels on pipe. I would simply say we don't have a significant backlog. We typically try to keep, in terms of our fracs, about 25 wells that -- out in front so we never have our frac crews waiting on our drilling rigs. If that was what you were concerned about the front end, we've got the inventory built there. And in the back end, in terms of keeping our barrels moving we're in good shape there.

Again, I would say in terms of the overall drilling and completion costs, we've been running about $8.5 million. We will take that down, as I said just a moment ago, to just below $8 million drilling and completion and then we'll have some additional facilities costs on that, that will bring that up to about $8.1 million. I would simply indicate that as we look at our opportunities to keep driving costs down in the Eagle Ford, we do indeed see some opportunity, particularly on the stimulation side, the frac cost side, to continue to drive some of our costs down there. On the drilling rig side, the greatest savings is going from 18 rigs to 16 rigs and being able to drill the same number of wells. That's what impacting our cost.

Good, that's very helpful. I had a second question just on corporate expenses, they're up from 3Q. Maybe I missed it. I don't know if there were any one-time charges in there. Should we expect those to revert lower in '13, closer to 3Q or any guidance would be helpful? Thanks.

Sure. I think if you look at the unallocated G&A it was up from $83 million to $134 million, and interest expense was up from $53 million to $61 million quarter-over-quarter. And there's about $25 million of comp and comp related expenses that are really of an unusual nature and would not expect to see them recurring. We had about an extra $10 million of IT expense in the quarter. Our IT spend did not exceed our budget or our plan for the year, but it was very much back end weighted and so that's not a run rate that you should expect to see continuing.

In addition, we have a tax sharing agreement with MPC and relatively small amounts quarter in and quarter out. Over time, they will be income neutral, but in the fourth quarter showing up in the unallocated G&A was about an $11 million expense associated with the MPC tax sharing agreement, which will be offset. Again, that will be income neutral, so don't think of that as recurring either.

When you look at interest expense quarter-over-quarter, it was up about $8 million. And as you know, we issued the debt -- $2 billion of debt in the fourth quarter and while it was very, very attractive interest rates, it still was more expensive than the CP that it replaced. So interest expense is going to be up marginally quarter over -- that will be ongoing and then there's always a little bit of noise in the G&A and the interest numbers, lots of other miscellaneous things. But I think that if you look at the third quarter, unallocated G&A, it is probably closer to a reasonable run rate. Although, with ramp-up in activity levels you're going to see some natural inflation in there. I think Clarence alluded to the fact, we're looking at ways that we can more efficiently operate so that we can produce greater value for the shareholders.

Great color. Thank you.

Arjun Murti, Goldman Sachs.

Clarence, just a couple of international questions. I think you mentioned in the release the Kurdistan Declaration of Commerciality. Could you just talk about the next steps there, what capital order of magnitude we may be looking at? Just on the Gabon subsalt well that I think spuds later this quarter. Is that one where the fate of the block is dependent on this first well, or are there multiple prospects? Thank you.

Arjun, I don't recall making a comment on Declaration of Commerciality in Kurdistan. We have had the very successful second well drilled at Atrush.

Yes.

And perhaps maybe you're referring to --

I apologize. It's been filed I think according to your release. Maybe not declared. Apologies.

Okay. And of course, earlier this week, I think, one of the partners in that project disclosed some independent reserve reports that they had done on the asset. But at this point, obviously we'll continue to participate there. We're very anxious to see the commerciality of how these barrels will be brought to market, given some of the difficulties that are ongoing there today, particularly because the relationships between Baghdad and [Rabeel].

In terms of our spending there this year, it's the Harir well that we've indicated the first well was a dry hole. We have two wells drilling today on the Mangesh and Gara wells that are on the Sarsang block. We'll have another well, the east Swara Tika well, drilled later this year. Then we'll be following up with two of our operated wells, one at Safin and one at [Murwawa], which is on the same block as the Harir well. I don't know that we've given necessarily the full investment there. I would simply say that we have farmed down, as you know, 35% interest in our two operated blocks, Arjun, and we have mitigated further, I would simply say, our financial exposure to the drilling. And so we're going to get a very cost efficient evaluation of these prospects in 2013.

Thank you. Then just on the Gabon presalt and one done or is there more prospects there?

I'm a former explorationist, Arjun, so you never want to say one and done. It is going to be a very important test because it is on a very large structure. These structures are all defined by 3D seismic. The question mark of course is the presence of the reservoir, or the quality of the reservoir out there in the deepwater as well as the access to source. We see the salt seal above these structures.

So I'd never say that one well in that large a block can completely make or break the block, but it's going to have a very significant impact certainly on our view of it. It's a very promising well and we look forward to it. I think the spud was originally mid-February and now it looks like it's going to slip into March. So we'll watch that with great anticipation.

That's great. Thank you so much.

Guy Baber, Simmons & Company.

Thanks for taking my question. You guys touched on this briefly earlier, but was hoping you could comment on recent North Sea production trends? I believe about a year ago you were expecting a 2012 production at Alvheim to average about 80 a day and it looks like it actually came in around 90 so you've outperformed there. Can you just talk about what all you've done to improve the production there and maybe you could give us your latest thoughts on extending that plateau and what declines could look like in '13 and '14? So, do you see some upside to that 70,000 barrels a day in 2013 that you mentioned earlier in light of some of the recent performance?

I wish I could answer that affirmatively, but I would say the extraordinary work that our team has done in the past, not just in raising 2012 production above what we said, but if you look back historically at what our 2008, 2009 plan said, we have really outperformed for several years here. To your point, extended the plateau and raised the plateau to a higher level of 90,000 barrels a day in 2012 and that was a combination of additional tie backs to Alvheim. But again, pretty extraordinary reservoir work and operating reliability on that asset. That's allowed us to achieve some really top core tile performance.

There is no getting away from the decline we see in 2013. It is about a 20,000 barrel a day decline to average around 70,000 BOE per day. We continue to advance projects like [Boyla] that we'll be able to tie back to Alvheim. That will help flatten the decline in the future, when that project comes on, I believe at the end of 2014. But, the decline will still be there. We certainly continue to look for new opportunities to tie back within the acceptable radius, but I think we've pretty much exhausted that opportunity set.

We'll continue to operate the asset on as low a cost and reliable basis as we can, because as I've said before, despite the fact that Norway is a high tax rate country, these barrels get a very premium price, obviously Brent type prices, and have low cost. So it is still a strong margin, highly profitable barrel.

Okay. Great. And then also, you raised the Bakken guidance, but one could argue that it's still conservative in light of some of the recent performance. So my question is, how conservative might that guidance be and what type of activity levels does it imply for you all for the year? Sorry if I missed that earlier. And also, what might cause you to accelerate activity there? Certainly realizations have improved, prices have been strong, I assume you've gotten some service costs relief. Just wanting to get a sense of what you might need to see to get more active there?

First of all with the guidance, or the activity levels, it will remain at five rigs this year. We do have two frac crews active. We may indeed be able to scale that back to one frac crew and that is to drill about 65 operated wells. To your point on the guidance, I recognize that in the fourth quarter we hit in essence what is our -- was our guidance for -- higher than our guidance for 2013, so we're simply looking at that. But I would tell you that we have to be careful because it is wintertime up there. You will have noted that our January production is below where we were in the fourth quarter. Weather can have a very significant impact on that. But again, our team continues to perform extremely well.

Would we look at additional activity? We will. And to your point, we have seen improvements in Bakken pricing, as rail has opened up additional outlets, eliminating some of the bottlenecks. We too have increased our use of rail. You go back to January of 2012, we only railed about 5% of our barrels. Now we're up to 40%. We'll continue to look at that as a good opportunity, certainly in 2013, when we think the differentials will support that activity. But we don't want to lock into long-term activity until we get a better sense of how overall infrastructure builds out and differentials are impacted. We certainly will look at that possibility of ramping up if we see the right conditions.

Very helpful. Thanks.

Blake Fernandez, Howard Weil.

Folks, good afternoon. Thanks for taking the question. Had a question on divestitures, maybe two specific assets if I could. One, the Marcellus was noticeably absent from commentary. I was just curious if you are planning to move forward there or potentially exit? And I guess a similar question on Libya. Obviously the production has ramped back pretty aggressively here.

I've read recent press reports that suggest there could be upside production potential in the area, which could potentially garner some interest from some of your larger peers. And, I just curious if that could potentially be an asset you would look to divest and help normalize this erratic tax rate that we've been seeing? Thanks.

Blake, I guess on the first piece, it is our intent, if we are able to secure the right value, to exit the Marcellus. I think we've been pretty well upfront about the fact that, that is not an area that is core to us and so that certainly is something we're looking at. With respect to Libya as a sale candidate, as I've said before, Blake, we don't comment on specific assets that we haven't announced for sale. Simply because we believe that weakens our hand if indeed we ever do elect to monetize an asset. At this point, I simply would say, you're right that this asset has great upside.

We've said in the past, and most recently the NOC has said in the past, that it's an asset capable of producing upwards of 600,000 barrels a day from the current 320,000. The key to realizing that is going to be to develop some major projects that have already been discovered and are in the planning process. So we see strong value in this asset going forward, despite its high tax rate. I recognize it has a high tax rate but the nature of that contract is that no matter what the oil price is, Libya will always generate positive earnings and as well as likely positive cash. It is a very favorable contract in that regard and it's a high return asset. So we'll continue to move forward with it.

Okay. Great. My second question, Clarence, if you don't mind just addressing quickly -- I know there was discussion of potential MLP in the Eagle Ford with regard to the midstream take away capacity, I didn't know if you had any updates there on where you stood?

No, it's really way too early at this point, Blake, for us to begin exploring that. I think we certainly see that as a possibility in the future when we finally reach a stage that we have built out the infrastructure and are convinced that we're able to capture the value of our production, which is the highest priority here. We do need to maintain control over that infrastructure to move our barrels to where we see the best value. But we've still got more work to do there.

As you heard me say before, we're going to have to determine ultimately what is the plateau level of production that we want to get to in the Eagle Ford. As I've said before, we're not going to run to a peak and then decline. We want to reach a plateau that we can maintain for several years so we can build out the infrastructure to meet those needs and not end up with over capacity very shortly after reaching a peak production. So, I think for now we're going to continue to move forward, building out what we need. When it's all said and done, we've got some operating history in that asset. We can look at whether or not an MLP allows us to capture incremental value from it. But that's not a near term priority.

Got it. Thank you very much.

Edward Westlake, Credit Suisse.

This is Scott Willis on for Ed. I just had a quick one on the Eagle Ford. Looks like your production is ramping pretty nicely and the per well economics are attractive as well. I was just wondering what your expectation is for when the Eagle Ford may begin to contribute to the free cash flow of Marathon as a whole? I just have one follow-up.

We've said consistently, I think from the time we did the Hill Corp acquisition, that we saw the Eagle Ford turning cash flow positive in 2014 and that is still the case.

Okay. Great. And then just on the Eagle Ford infrastructure, looks like you're spending about $190 million this year. I was just wondering how your spending may look going forward in relation to that over the next few years?

I think this year is going to be about 50% of where we were last year, a little more than that, and I think we would expect 2014 to be 50% again at that point. I probably wouldn't want to comment much beyond that. In part, that's going to determine at what level, again, do we want to focus in on a plateau type of production that we would build out to.

Okay. Great. And then just last one on the [Diomond] well, do you have a pre-drill resource expectation there?

I believe we did have that in our presentation and I want to say it's -- we said 250 to 800 million barrels of gross resource potential.

Thank you.

Paul Cheng, Barclays.

Hey, guys. Good afternoon. Janet, I just want to follow up with a earlier question, just want to make sure I understand. On the deferred tax as a Company as a whole, not just in the US, as a Company as a whole, should we assume that in this year as will turn into a positive cash flow item?

Next year, yes -- well, yes, this year, 2013, yes.

Will already turn into a positive cash flow item. Okay. And Clarence, great that you provide some data on Eagle Ford on the unit core structure. Do you have a similar data that you may be able to share on Bakken?

I don't think we're prepared to show that. The Bakken has grown at a more modest and measured pace and has not had the impact on our overall US aggregation that we've seen in Eagle Ford. We're trying to not get into a place, Paul, where we end up giving detailed numbers on all of our major assets. But Eagle Ford, we felt we needed to do it, because at the rate that it's growing and the impact that it's having, not just on our US business but the Corporation as a whole, we felt we needed to give investors guidance on that asset because it's fairly unique in our portfolio at this point.

Clarence, in the Eagle Ford -- where else that you're going to drill in 2013, are they -- what's the percentage going to be in the black oil window and comparing that to 2012?

Yes, I think, Paul, it's about -- let me check. I want to say about 75% to 80% of our wells are in the high GOR trend. The bulk of the rest are in the condensate window. I think that's -- we'll confirm that, but --

Do you have that number for 2012? I just want to see how that is being shipped.

It was actually about the same, Paul, in 2012. So, even though we have said we're going to focus as much as we can in the high GOR window this year, because of the lower NGL and gas prices. Last year with trying to hold leases and meet our obligations, as it turns out we'll have about the same proportion in the high GOR window in 2013 as we did in 2012. Had we embarked on our original plan, before we saw the collapse in NGL prices, we'd have a much higher percent in the condensate window. That was part of our plan originally, was to accelerate our drilling there. But again, with what's happened with NGL prices and we've redirected that into the high GOR area.

Thank you.

Faisel Khan, Citigroup.

Thanks. Good afternoon. I think I got the well results for the Eagle Ford, about $8.5 million per well is where you guys are at right now. How much are your wells coming in at the Bakken?

About $8.5 million to $8.8 million.

Okay.

We still think, Faisel, that's best in class up there.

Fair enough. Any more potential improvement in that number going forward for the year or is that pretty much --?

A little bit. In 2013, most of our wells are going to be on pad drilling, but we don't see as much savings on pads in the Bakken. Because, to a certain extent we're doing it in the Bakken for access to locations, topography issues, and we actually end up drilling longer laterals from some of the pads that offset some of the cost savings you get in less movement -- less move days. We don't see a lot of improvement at this point, but we continue to believe our costs are going to be best in class.

Okay. Fair enough. And then just on the pure unit profitability in US E&P, you certainly have ramped up production at a pretty high clip in the Eagle Ford and the Bakken and just want to understand when do we see the bottom line results from all that production ramp? Because you look at the 2012 per unit costs, per unit profitability that came down versus 2011, so just trying to understand how you guys are thinking about per unit profitability of this set of assets going forward over the next couple of years?

Yes, I think certainly the cash -- the unit cash margins are going to be strong because as we've shown here, our cash costs, whether field level controllables or the other cost, are coming down and driven in large part by the higher volumes. The earnings contribution is going to be a bit more muted and again it comes back to the impact that Eagle Ford has on the overall DD&A rates. So when you look at 2012 actual and the 2013 guidance we've given you, the 2013 DD&A rate is going up pretty significantly. That is largely due to the Eagle Ford barrels now being a larger component of our US production.

As we see that Eagle Ford DD&A rate come down in subsequent years, as we book both performance reserves as well as higher hopefully initial bookings, as our confidence in the reservoir performance grows, we're going to see that DD&A rate come down. In the meantime, it is going to have that impact on earnings margins, while cash margins I think are going to continue to improve. We are of course, as I mentioned before, seeing declines in our Gulf of Mexico barrels, which have been very strong cash flow providers in the past.

Fair enough. Last question from me. It seems like if I read your numbers correctly on the infrastructure that you guys have spent in the Eagle Ford and what you plan on spending in the Eagle Ford that you'll have over $1 billion of invested capital in midstream and infrastructure assets in the Eagle Ford. In the long run, I know there was a question on the MLP, but do these assets get sold eventually when you reach that peak production level or do they have to remain part of the upstream portfolio? What's your opinion on whether these assets have to remain with the Company or not?

Again, I'm not sure that we get quite to $1 billion. My math doesn't get me there. It does become a very significant investment nonetheless. I think, obviously, the number one priority for us in terms of that infrastructure is flow assurance and the ability to move to where we see the best realizations. If we can achieve that, that's why I come back to the discussion around MLPs, that's not our primary interest today.

Ultimately, if it's an MLP or it's a flat-out sale of the assets to someone else who will own them and operate them and we'll pay a tariff or throughput fee, we'll certainly look at that. But again, you don't want to have, whatever ultimate production is out here, well over 100,000 barrels a day, held hostage to midstream assets. You want to be able to control that so you can control, again, the ultimate commerciality and marketing of your barrels.

Great. Thanks for the time. Appreciate it.

Kate Minyard, JPMorgan.

Hello, good afternoon. Thanks very much. Just wanted to ask a couple of questions on reconciling the DD&A costs, especially in the US and the Eagle Ford, on a go-forward basis or for 2013 to the F&D costs? Given that you talked about preliminary F&D being about $17 per BOE, but attributed a lot of the bookings to the Eagle Ford and Bakken and Oklahoma, just trying to look at how the F&D reconciles with the DD&A expected in US E&P, and whether there's some infrastructure costs that are loaded into the DD&A that maybe wouldn't be reflected in the F&D costs? Then I've got a follow-up.

Well, it's not a simple calculation, Kate. I think there is a component of midstream in the DD&A rate but it's not a big component. In the DD&A rate, obviously, are the acquisition costs that we've incurred in the Eagle Ford. So that is a substantial component of it. The other thing is when you calculate DD&A rates, it's largely on the P1s or the proved developed reserves. Whereas, when you look at our F&D cost, it's proved developed and proved undeveloped. So you've got a larger proved reserve figure in the F&D cost than you would have in the DD&A rate. I think those are the primary reasons.

Okay. And then my related follow-up is whether the idea that you're not able to book the whole well EURs initially, whether we could then expect to see maybe a catch-up or a sudden influx of significantly more efficiently added reserves, maybe in 2013 or in 2014, as you prove performance in the plays? And whether that would then in turn lower F&D costs in future years? Thanks.

It certainly goes to future reserve bookings are going to go to F&D of costs and they're going to go to DD&A rates. Two things happen. One is as you begin to produce a well in the current year you'll book a portion of the EURs. Then you'll book the rest over subsequent years, as you see performance and as our reserve auditors get the comfort that it's more likely than not that these reserves are going to be recovered. So, you've got incremental reserve bookings from performance. You also potentially, as you go through the future years and the confidence in the EUR grows, your initial reserve booking at the time you bring that well on production will rise as well.

All of that contributes obviously to F&D cost as well as it does to lowering the DD&A rate over time. The way the DD&A rate works, if you look at just the life of a project, when you start out in the early days of production the DD&A rate is way too high and when the last barrel is produced, DD&A rate is way too low. Somewhere in between there it really is the average. It is the right number. But that's the nature of these emerging plays where there isn't a lot of long production history that can give us a certainty to book the full reserves up front.

Okay. Great. Thanks for the clarification.

John Malone, Global Hunter Securities.

Yes, good afternoon. Clarence, it sounds like you want to withhold comment on the Eagle Ford pilot programs until Q2. But can you speak at all to, I think it was about five distinct projects you were running, is that still the number? Have any of those fallen off? Are there any more open choke wells you think you're going to run similar to the Borough? Or have you proved your point with those?

John, we have nine pilot projects under way and we're withholding -- we're not withholding comment because we're trying to hide anything. It's just that as you recognize, it's not until you get meaningful production performance out of these pilot projects that you can begin to draw some conclusions. As it's been suggested to me by my people, we're -- even to do so, to draw conclusions by the middle of this year we're pressing it a bit.

Nevertheless, what we're looking at is pilots to test the lateral displacement of the wells, the horizontal displacement of wells within the reservoir, as well as different stimulation methods including, to your point, some of the wells looking at larger choke sizes. We're on a course to learn as much as we can, as rapidly as we can, in the Eagle Ford so that we can then make that part of our standard operating practice, and as we drill 300 or so wells a year do so in a way that gives us the highest value.

Okay. Thanks. And then just unrelated, in Kurdistan, anything you can say about what you learned from the Harir well and how it informs what you're going to do in the next wells there in the Safin?

We saw very good reservoir in the well. That is encouraging. There appears to be, perhaps, a bit more structural complexity in -- at least on the Harir prospect than we may have thought. The seismic quality there is not very good, so being able to image the subsurface as well as we'd like is a bit challenging. But I would say that at this stage the prospects we see, the other prospect on the same block and the prospect on the Safin block, are rather unique. I think we still hold out high hopes for those and we'll have those drilled pretty quickly here.

Okay. Thanks.

Amir Arif, Stifel Nicolaus.

Thanks. Good afternoon. In the Eagle Ford if you keep with a 300 rig program, roughly, at what point does production start to flatten out or level out? Can you give us a sense of that?

I'm sorry, did you say with a 300 well program?

Yes.

Again, I think that's the question we are going to try to resolve in the second half of this year when we have the results of the pilot program. So, I'll give you an example. We have previously, I think at the time of the Hill Corp acquisition talked about peak production of 125,000 BOE a day. As you can see from the numbers we've given for guidance for 2013, we should exit 2013 at about 100,000 barrels of oil equivalent per day. Depending upon the overall size of the resource base we have here, which again is going to be determined in large part by the pilot results, we could have a decade of drilling out here at current drilling levels.

And so exceeding 125,000 barrels a day, I think, is a very likely outcome, but I think as I indicated before, we don't want to build up to some peak of -- say, let's just say for purposes, 150,000 barrels a day, only to see that decline within a year or two. Our preference would be to build to a lower level that we can sustain for a longer period of time, again, so we can optimize our midstream investment and not over-build capacity that's going to be under-utilized. I can't give you a number. I think at this time I think we see tremendous upside for this play. We're going to be in this play for a long period of time. As we get the full data set from our spacing pilots, we'll be able to give better guidance on where we see this asset ultimately getting to.

Appreciate the color. Just in terms of second question, you got a very active exploration portfolio going on. Which one prospect gets you the most excited in terms of the resource upside that you're testing here in the first half? Would it be the Gabon well?

If I do that, I'm going to put the grievory on it. I hate to do that. That's bad luck. They're all good prospects.

Okay. Thank you.

Roger Reed, Wells Fargo. Roger, if your line is on mute, can you unmute your phone? Okay, we'll move on. Eliot Javanmardi, Capital One.

Hey, guys, good afternoon. Just a quick question. First, wanted to make sure I heard clearly, the 6% to 13% stretch target for production, could you clarify the time line on that and what that includes? Is that total E&P we're looking at excluding Libya?

It's -- yes, go ahead, Howard.

Eliot, that's total upstream production excluding Libya out of both 2012 and 2013 and excluding the Alaska asset out of both 2012 and 2013. The way we couched it early last year was we were going to grow at 6% to 8% excluding Libya and dispositions. So, Alaska was disposed so we've taken that out of both years and Libya as well. That's where you get to the 6% to 12% -- 13%, excluding those. But the target we set last year was 6% to 8%. That's the target we're living by.

Sure. Absolutely. Short follow up then, or even a separate question, excuse me. If you have it in front of you, what is comprised of other US production at this point in time? How much of that is Gulf of Mexico and what else is out there?

Gulf of Mexico we'll give you that number here.

Rocky Mountains, some non operated Permian, some Oklahoma, East Texas, conventional plays, those are the majority of the other US.

Gulf of Mexico is 18 for 2013.

Gulf of Mexico is 18, I'm sorry?

Yes.

Okay. Thank you very much.

Pavel Molchanov, Raymond James.

Thanks for taking the question. I apologize if you mentioned this already. Did you have any negative natural gas reserve revisions last year?

We did do the prices, very minimal, not large quantities.

Okay. Immaterial, basically?

Yes.

Okay. And then just a quick one on going back to what you mentioned about the Canadian potential sale. As you know, there's been a lot of political debate in Canada over allowing foreign acquisitions, particularly in the oil sands. Do you see that as a hurdle to potentially monetizing a portion of that asset?

No, I would only say that I think the recent Canadian pronouncements around foreign engagement in their assets has actually been a help because if we were to do a sale of a portion of our interest in AOSP, it would be a non operated interest in a joint venture. That is something that they've actually given greater certainty around, greater confidence in being approved. So it's actually removed an uncertainty, I would say, that was out there previously.

Appreciate it, guys.

John Herrlin of Societe Generale.

Hello. Just a quick one on reserve bookings. I guess it's philosophic. You guys always strike me as being more conservative than your peers and now you're getting into more unconventional exposure. Why don't you have comparable PUD percentages? Many of your peers are in the 30%s or higher.

You know, John, I think we're actually this year pretty close to 30% and then if you back out the oil sands, which of course is essentially all PDP, our PUDs are actually more than that. I don't have all the numbers in front of me, but -- we don't think of ourselves as conservative. In fact, we try to go straight up the middle of the fairway following the SEC guidelines, which as you know are inherently conservative. What we think of as our ultimate EUR is actually proved plus probable because the definition of proved plus probable is that it's as likely as not that you will outperform as under perform.

Okay, Janet, most of your larger peers are in the 40%s. I didn't think you were quite that high, even adjusting it out, but thanks.

John Malone, Global Hunter Securities.

Just a quick one for Janet. Any new hedges you put on beyond those ones you put on in August?

No.

Thank you.

Thank you. We have no further questions at this time.

Thank you, Christine, and we appreciate the interest in all those callers and those that listened to the call today. If you have any additional questions please don't hesitate to give Chris or myself a call. Have a great evening. Thank you and good-bye.

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