馬拉松石油 (MRO) 2010 Q4 法說會逐字稿

Welcome to the Marathon Oil Corporation, fourth quarter and full year 2010 earnings conference call. My name is Monica and I will be your operator for today's conference. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded. I would now turn the call over to Howard Thill, Marathon's Vice President, Investor Relations and Public Affairs. Mr. Thill, you may begin.

Thank you, Monica. And I, too, would like to welcome you to Marathon Oil Corporation's fourth quarter 2010 earnings webcast and teleconference. The synchronized slides that accompany this call can be found on our website, marathon.com. On the call today are Clarence Cazalot, President and CEO, Janet Clark, Executive Vice President and CFO, Gary Heminger, Executive Vice President Downstream, Dave Roberts, Executive Vice President Upstream, and Gary Peiffer, Senior Vice President of Finance and Commercial Services Downstream.

Slide 2 contains the forward-looking statement and other information related to 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, 2009 and subsequent forms 10-Q and 8-K cautionary language identifying the important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

In the appendix of this presentation is a reconciliation of net income to adjusted net income by quarter for 2009 and 2010, preliminary balance sheet information, first quarter and full year 2011 operating estimates and other data that you may find useful.

Moving to Slide 3, our fourth quarter 2010 adjusted net income of $780 million was a 241% increase over the fourth quarter 2009, and 10% higher than the third quarter 2010.

Slide 4 shows key drivers to the fourth quarter over quarter increase in adjusted net income. Earnings before tax for all four segments were lower, but the decrease was offset by lower taxes, which resulted from a shift within the quarter toward greater domestic versus foreign income, along with normal year true-ups -- year end true-ups. The quarter to quarter difference in taxes was also impacted by the absence of currency fluctuations in prior quarters. The overall income tax for 2010 was 50%, within our previously provided guidance of 49% to 54%.

For 2011, we expect the rate to be between 54% and 59%, and please remember, the overall rate is highly sensitive to the mix of income and can fluctuate from quarter to quarter. As shown on Slide 5, our adjusted net income more than doubled year over year going from $1.2 billion in 2009 to almost $2.6 billion in 2010.

Slide 6 shows the key drivers to this year over year increase in adjusted net income, including significantly better earnings in both our E&P and downstream businesses, partially offset by higher income taxes and lower earnings in our oil sands mining segment.

As shown on Slide 7, E&P segment income was slightly lower for the fourth quarter compared to the third quarter 2010. Higher realizations and sales volumes were largely offset by higher domestic DD&A, associated primarily with the Droshky field and higher exploration expenses.

Average E&P realizations and market indicators are shown on Slide 8. Quarter over quarter, our average E&P realization per BOE increased $6, while NYMEX profit WTI increased $9 per barrel and the bid week of natural gas price decreased $0.58 per MMBTU.

Slide 9 shows our E&P production volumes. Production sold increased 5% from the third quarter to the fourth quarter. The higher sales volumes in the fourth quarter 2010 as compared to the third quarter were a result of a smaller underlift in the fourth quarter. We ended the year approximately 3.4 million BOE underlifted. The makeup of this underlift was 2.1 million BOE in Alaska gas storage, an underlift in Europe of about 700,000 BOE, and both EG and Libya being underlifted by approximately 300,000 BOE.

Fourth quarter 2010 production available for sale increased 3%(Sic-see presentation slides) from the third quarter 2010 and 4% from the fourth quarter 2009. These increases were primarily a result of a full quarter of Droshky production.

Turning to Slide 10, compared to the prior quarter, fourth quarter E&P earnings per BOE decreased $12.95, primarily a result of the higher exploration expenses largely attributable to unsuccessful exploration wells in Indonesia and Norway, higher DD&A from Droshky and higher field level controllable costs and other expenses. These negatives were partially offset by higher commodity prices and higher volumes. Total operating cost per BOE increased from $24.47 to $33.34 quarter over quarter.

Slide 11 shows the trend by quarter over the last three years for field level controllable costs and exploration expenses per BOE. The increase in exploration expense per BOE is attributable to the aforementioned dry wells. The increase in field level controllable costs per BOE is largely a result of workover costs in the Gulf of Mexico, timing of international listings, and year end accruals from outside operator properties, which added $0.66 per BOE to the fourth quarter result.

Turning to Slide 12 and oil sands mining, fourth quarter segment income was $9 million, which reflects both positive price and volume variances over the third quarter, offset by one-time startup and ongoing costs at the Jackpine mine, and increased blend stock volumes and costs. Net synthetic crude sales for the quarter increased 38,000 barrels per day, as production continued to ramp up at the Jackpine mine.

We'll now move to Slide 13 and I'll turn the call over to Dave Roberts to discuss 2010 upstream highlights.

Thanks, Howard.

Despite the significant challenges in 2010, the upstream business continued on a path to create sustainable profitable growth options for the company. As noted in our release this morning, we have expanded our presence in unconventional resource plays, both in the United States and internationally, with a strong preference for liquids-rich opportunities. Our Bakken position now spans almost 400,000 acres. Production continues to grow, and our targeted peak of over 22,000 barrels per day, is in view. We have six rigs in continuous drilling operations and one rig planned to handle completions across our assets.

Marathon also holds 86,000 acres in the Anadarko-Woodford area, an area where we have operated for decades, and we have line of sight on new opportunity to increase that position to over 100,000 acres shortly. Importantly, we will have 8 rigs in the play by 2011, by the end of this year. We've also entered two new unconventional plays in the lower 48 and believe there are further opportunities we can access. We have an option on 75,000 acres in the Eagle Ford Shale of South Texas and will likely expand that position further in 2011. And we built the position of over 170,000 acres in the Niobrara play across the DJ Basin. Again, importantly, we'll be drilling wells in both these plays in 2011, with two and one-rig programs respectively to begin with, and the capability to expand as conditions warrant.

Internationally, we built our position in Poland to over two million acres and we will drill in 2011 to begin testing this play, and in Canada, we started an evaluation drilling program over the winter to test our 100% owned in-situ asset of Birchwood. As we remain committed to impact exploration opportunities, we took a position in four blocks in the Kurdistan region of Iraq, moving from early stage discussions to completion in less than three months. We are currently engaged in drilling and testing operations on two of the blocks and we'll be progressing operated activity on two 100% blocks throughout this year.

A key driver for 2011 performance began its debut in 2010, as the Jackpine mine commenced startup in the third quarter. The upgrader for the project is currently in startup phase, so we will soon see the full benefit of our first expansion at the Athabasca project. We also had continued successful exploration in Libya with seven new discoveries. As we look forward to a potentially different future as an upstream enterprise, we are focused on two things that will make us successful in the future. The first is disciplined investments leading to sustained reserve and production growth.

In 2010, we replaced on an organic E&P basis 95% of our reserves, offsetting a significant impact to the negative in the Gulf of Mexico. Importantly, showing our focus and discipline towards liquid-based activities, we replaced 109% of our liquid hydrocarbon production with 72% on gas replacement, as we focused on value with our capital dollars. Our strong held by production asset base gives us tremendous flexibility in this regard.

Finally, our operational reliability continues to improve at Marathon. We executed several major turnarounds flawlessly in 2010, and we had overall 94% operational reliability across our operated assets. High reliability yields are most cost effective in valuable barrel. All in, 2010 was a solid year for us. We have a lot more to do, that's for certain. But we are building in reliability to our base portfolio, and adding significant growth options in both unconventional and impact areas, all creating a sustainable growth platform for the future.

I'll turn the call back over to Howard.

Thanks, Dave. Moving to our downstream results and Slide 14, RM&T's fourth quarter 2010 segment profit totaled $213 million compared to an $18 million segment loss in the same quarter last year. Because of the seasonality of the downstream business, I will compare our fourth quarter 2010 results against the same quarter in 2009. Our crude oil and other feed stock costs were lower than the change in the average price of LLS during the fourth quarter 2010 compared to the corresponding quarter last year.

As shown on Slide 15, the primary reason for the relatively lower cost was the increase in the sweet-sour differential of approximately $2.25 per barrel. And an increase in the percentage of our sour crude process through our refineries of approximately 15%. In addition, the futures market was in contango, $1.20 per barrel on average in the fourth quarter 2010 compared to $0.71 per barrel in the fourth quarter 2009, which also reduced our actual crude costs compared to the LLS price used in the crack spread calculation.

While we completed the sale of our St. Paul Park refinery December 1, 2010, we still increased our total throughputs about 200,000 barrels per day, or approximately 20% over the same quarter last year, primarily because the Garyville major expansion project was online for the entire fourth quarter 2010. In addition, some other work, which we recently completed in our refineries to improve the efficiency of our fluid catalytic cracking unit, also improved results over the fourth quarter 2009. Partially offsetting these positive improvements compared to the corresponding quarter last year, manufacturing and other expenses were higher in the fourth quarter 2010, primarily because of higher maintenance and other manufacturing costs.

Speedway SuperAmerica's refined product and merchandise gross margin was about $16 million higher in the fourth quarter 2010 compared to the fourth quarter 2009. The increase was primarily due to higher gasoline and distillate margins, which increased from $0.10 per gallon in the fourth quarter 2009 to $0.14 per gallon in the fourth quarter 2010. SSA's same-store merchandise sales increased approximately 4%, while same-store gasoline volumes increased 1% quarter to quarter.

Slide 15 provides historical performance indicators for the downstream business and previously discussed LLS 6321 crack spreads. We'll now move to Slide 16 and I'll turn the call over to Gary Heminger for a review of 2010 downstream highlights.

Thank you, Howard.

2010 was a pivotal year for the Marathon downstream. We completed the integration of what is essentially the first new refinery in the US in over 30 years. The Garyville major expansion has exceeded our expectations by outperforming the design specifications. In addition, the Detroit heavy oil upgrade project approached the halfway mark on schedule and on budget and we have accomplished outstanding safety records along the way. Our Speedway and brand marketing components managed to continue to excel in basically a flat growth market.

Now, let me give you a little more color on the highlights that I've just mentioned. First of all, the Garyville major expansion project has been operating for almost a year and we are very pleased with the performance and additional value generated in the new plant. Most process units are outperforming their design criteria and we have raised the rate of capacity to 464,000 barrels per day, or an increase of 208,000 barrels per day.

The new dock we constructed as part of the project increases our take-away capacity by approximately 40%. This dock in conjunction with the additional barrels of distillate produced has opened world sales markets and we began exporting distillate and gasoline since last spring to markets in Europe and South and Latin America. Our DHOUP project remains on schedule for startup in the second half of 2012. 25% of the construction is complete, and we've planned a very robust construction season here in 2011 and then we will complete the project in the second half of 2012.

Now, turning to our marketing components, Speedway had one of the best years ever and they were voted for the second straight year as best gasoline brand in the US. Same-store light product volume was up 3.7% for the year and 1.7% for the fourth quarter. Additionally, the Speedway team increased same-store merchandise sales by 4.4% for the year, and 3.8% for the quarter.

Turning to our Marathon brand organization, we realized an incremental sales increase of approximately 10% again in essentially a flat growth market. Our brand organization secured a significant agreement with The Pantry to sell a very large portion of our new transportation fuels from our Garyville project into the southeast market, and this is a long-term agreement. And with that, I will turn it back to Howard Thill.

Thanks, Gary. Slide 17 provides an analysis of total company preliminary cash flows for the year 2010. Operating cash flow from continuing operations before changes in working capital was $5.2 billion, while working capital changes from continuing operations contributed $750 million. Cash capital expenditures for 2010 were $4.8 billion, and dividends paid totaled $704 million, while asset disposals generated proceeds of over $2.1 billion.

The 2010 year end cash balance was approximately $4 billion. Slide 18 provides a summary of select financial data. At the end of the fourth quarter 2010, our cash adjusted debt to total capital ratio was 14%, a decrease of seven percentage points from the third quarter. As a reminder, this debt includes approximately $198 million, which is serviced by US Steel, and this debt is expected to be removed from our balance sheet by the end of this year.

Moving to Slide 19, I'll turn the call over to Clarence Cazalot for a look at Marathon's priorities in 2011.

Thank you, Howard. Let me begin with the overriding corporate priority, which is to effect the successful spin of our downstream assets effective June 30, and suffice it to say the financing and transition activities are progressing quite well. I think on the upstream, Dave has already talked quite a bit about the overall objectives there. I would point out, of course the increase in rigs in our liquids-rich resource plays from eight to 17.

On the downstream, Gary has talked about the major priorities there as well, and with respect to the cash side, let me address a question up front that I know you will all want to focus on, and that is what are the priorities for the free cash that we'll have? First of all, we want to ensure that both companies, at spin, will have very strong balance sheets. That's our highest priority for cash.

Secondly, as we had said before, we will want to fund profitable growth within the businesses and, again, as we have reflected earlier, an obvious priority in our upstream business is to increase our positions in the liquids-rich resource plays, primarily in North America, but internationally as well. Dividends, secondly, is always a very high priority for us, but as we see it today, the dividend yields on both of the companies at spin, will be very competitive relative to their peers, and lastly, stock buybacks continue to be a consideration and an option for us with respect to free cash flow. So with that, Howard, back to you.

Thanks, Clarence. Before we open the call to questions, I would like to remind you that to accommodate all who want to ask questions, we please ask you to limit yourself to two questions and you can re-prompt for additional questions as time permits. And for the benefit of all listeners, we ask that you identify yourself and your affiliation. Monica, with that, we'll turn it over to you for taking the calls.

Thank you.

(Operator Instructions)

Our first question comes from Doug Terreson of ISI.

Good afternoon, everybody.

Hi, Doug.

I have a couple of questions. First, Libya's a fairly relevant E&P position for the company and I wanted to see whether you guys have had any operational changes related to the security situation in North Africa, and also how you perceive the geo-political threat in the country, if you think it's meaningful.

Yes, Doug, this is Dave. We've not seen any issues there presently. Obviously we're keeping a close eye on what's been transpiring in Tunisia and Egypt, but as you know, that culture is very different than those other two and we have not seen any escalated presence of security or any appearance of a threat from the outside, and we're in constant communication with the Libyan government about things that they see them as well. Frankly, I don't think that we concern ourselves a lot with the contagion rolling across North Africa in that particular place, largely because of the very close manner in which that government is run.

Sure. Okay, thanks. And also had a question for Gary. Refining your marketing earnings would have been stronger absent the $66 million negative item. Wanted to see if we could get some color on that. And also, if you guys have quarter to date, Chicago and Gulf Coast LLS spreads similar to that which you have on Page 15, I would appreciate it.

Let me have Garry Peiffer talk about the $66 million.

Okay.

Yes, Doug. It was just a multitude of many small variances from quarter to quarter that just happened to total about $66 million. So it comes from higher primary transportation costs on our light product movements, a little bit higher employee compensation accruals and tax reserves, company benefits. It's just a myriad of things that were kind of spread across all of our operations.

Okay.

And, Doug, looking at the crack spreads on Page 15 that you were asking about.

Sure.

The -- here in the first quarter, just a few weeks in, of course the spreads have been very low in Chicago and the Gulf Coast. More importantly, though, the sweet sour differentials, because of some of the advantaged markets that we are in, basically the Canadian markets and some of the West Texas intermediate crudes that we can move through our system, we've been able to get those into the marketplace. So the spreads have been really what has been a benefit to us here so far in the first quarter. But the crack spreads, while I don't have a month to date number, I would say Chicago has been basically less than a dollar--

$0.69.

$0.69, Garry says. Do you have the Gulf Coast?

$2.18.

$2.18 month to date in the Gulf Coast.

That's through January, that's just January.

That's close enough. Thanks a lot, guys.

Thanks, Doug.

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

Thank you. Good afternoon, everybody. Can I try one for Dave and one for Gary? Dave, on the production outlook for 2011, I wonder if you could just walk us through a couple of the component parts that you mentioned in your prepared remarks. In the Woodford, I understand you have fairly material non-operated positions and if I am not mistaken, your partners are ramping up the rig count pretty dramatically, the outlook there, please, if you can give us an update on Droshky, both in the fourth quarter and reiterate your guidance for 2011. And finally in the Bakken, your well design, has that changed any in the context of your targets? We're hearing that basically you've moved to a little bit more aggressive frack stages, and I have a follow-up for Garry.

Okay, Doug. I counted three, but I'll see if I can remember them all. Let's start with the Bakken. I think one of the things that we've consistently done is we alter our completion technique based on where we are in the play, because as we all know, it's a very big play, and the reservoir is not ubiquitous, and so you have to change as the conditions warrant. And so I think there is some of the areas that we're moving into right now where we're actually pumping higher stages, in the fifteen to 20-stage range. But I don't think that that signals necessarily a shift to us going to that. We basically let the wells and the reservoir tell us what it is that we're going to need to do there as far as that goes.

The Droshky question, Q4 we had a 31,000-barrel per day average. The exit rate for the year is right at 28,000. We still expect this year to average between 15,000 and 17,000 barrels a day, depending on what kind of hurricane season we have. So still a very substantial decline, but, you know, still very strong rate at the present time. With respect to the question of the Woodford, I think what we're seeing is that our growth in the Bakken and the Woodford play in particular, where we'll see some pretty strong response will offset a lot of the declines that we'll see as we transition to some of our new activities in Norway.

And what I would say about our program there is we're going to gear up to have eight co-op rigs running so, you know, we'll probably get on the order of twelve to 20-some odd wells drilled with that portfolio, depending on when the rigs are ultimately delivered. We do expect a very strong activity from outside operated activities and I think we estimate on the order of thirty to 50 potential wells. The only thing I would caution you, is our working interest on the co-op side is essentially 60%. On average on an OBO basis, it's about 15%. So most of the activity that drives our production is going to come from stuff that we do.

Thanks Dave. My follow-up is very quick, you'll be glad to know. Garry, you've said, I guess often, about Texas City perhaps being a challenged asset. The other day BP has announced that they are selling Texas City in its own right. Do you see any potential scope for the interest in the asset and perhaps addressing the structural weakness in your facility down there? And I'll leave it there. Thanks.

Let me -- I read the same press release that you did yesterday. So I have had, in getting ready for the earnings release, had really no time to think about this asset. To say we have a structural problem, we don't have a structural problem. In fact, you see the Eagle Ford and some of this new crude coming on the market really puts Texas City in an advantaged position. So Texas City did well for us last year. It certainly just is not the high volume and high quality as in Garyville, Robinson, or Catlettsburg, but in its own little niche, it does okay and we'll continue to follow that through in the future.

Great, thanks a lot.

Our next question comes from Edward Westlake of Credit Suisse.

Yes, good afternoon, everyone. Maybe a first question for Gary on the downstream. Obviously, you know, a lot of refiners are trying to basically cut costs and maybe boost diesel yields, capture some cheap crude to try and boost their profitability in this kind of environment. Could you give us any sort of numbers in terms of your targets for Marathon's ability to do more with the asset base that it has?

Well, Ed, I've said several times that, you look at when somebody talks about max gasoline, max diesel, we believe we can flip our slate less than 10%. Usually it's in the 7%, 8%, depending the type of crudes, and the yield you get out of those crudes, but every day we are optimizing our crude slate to be able to take advantage of whether it's gasoline, diesel or other some of our other process units to get the best and most profitable yields. But it's pretty much in the, I would say 8% to 10% category, is how we can move.

Of course that also flips. We are advantaged in the Midwest, with our very strong refining position in the Midwest and looking at those crudes that are available sometimes, at an advantaged price versus alternative crudes, we certainly every day take advantage of those.

Is there any trend that you can talk to in terms of the amount of some of this cheap inland crude that you've been able to capture, or costs in terms of reducing operating costs?

Right, and that's a good question. When you really look at Cushing and you look at the different crudes either coming out of Cushing or coming out of Canada, everything is going to be determined by the amount of the infrastructure and the pipeline space that you can move through. And while there are some great spreads in the Canadian markets, really being caused by rehab work that's going to be required in the Enbridge systems, both 6A and 6B going forward. So, you know, until we finish our Detroit project, you know, if you could wish, I certainly wish Detroit was done now and we could run a lot more heavy crude in Detroit. But until we finish that, we will not be able to take much advantage of incremental Canadian crude until that period of time. And then other crudes coming out of Cushing or whatever is all going to be based on the amount of infrastructure that you could move crudes through.

And this is Garry Peiffer. Just one other item on the distillate, I think you see in our press release here that in the fourth quarter of '10, we produced about 461,000 barrels a day of distillates, that compares to 346,000 barrels a day last year, so substantial increase in distillate production, which based upon just crude oil inputs, rather than total inputs, but we've increased from about 35% of distillate to 39%, and that's being primarily driven by the GME investment, which goes to your question on diesel, increasing our diesel production.

Ed, when we built Garyville, our plan was to try to do approximately fifty-fifty distillate and then gasoline and other components.

And maybe a follow-on for Dave. Just on the AOSP, when do you reckon you'll get up to full profitability, which costs are obviously as you get that facility up?

Well, I think most of the kit will be up and running full stream by the end of the quarter. The real, the real key is the residual hydro cracker, which will give us full capacity in the upgrader, probably will drift into April, would be my guess. So, you know, we're -- end of the first quarter, end of April, for sure.

Thanks.

Thanks, Ed.

Next question comes from Faisel Khan of Citi.

Good afternoon.

Hello, Faisel.

If you could help me just bridge the cash balance from the third quarter to the fourth quarter. I think I got the year-over-year stuff right and I think I got the asset sale in December in there. But how much of a working capital gain was there sequentially third quarter to fourth quarter?

In the fourth quarter, we had just over $1 billion I think of cash provided from working capital.

Okay.

Let me double-check that for you, Faisel.

Okay, got you. And just on the Canadian, on the oil sands business, you guys talked about the higher startup costs, but you also talked about the blend stocks, higher blend stock costs, too. Can you just elaborate exactly what was going on with that? Is that because of the residual hydro cracker wasn't available?

No. Faisel, I guess one of the things we try to show when crude price goes up, the blend, the blending agents, diluents that we use in order to be able to move the crude around, those costs go up as well. So they tend to wash each other out, but that's just a function of the operation. In fact, you have to blend that stuff in order to move it down the line to the upgrader.

Okay, got you. And last question. The way your LNG contract works with BG? Is that a fixed amount of volume every quarter, or is there -- how much excess LNG capacity do you have to sell into the spot market?

Any, any volume that we have is committed to BG.

Okay, understood. Thank you.

Thanks, Faisel.

The next question comes from Evan Calio of Morgan Stanley.

Hello, good afternoon guys.

Hi, Evan.

Don't we get four questions if you guys are going to separate?

July 1, July 1.

I'll ask two questions, really one upstream and one, a bit of a follow-up on the downstream side. With regards to the lower 48, and thanks for the increased granularity on CapEx and volume outlook in the Bakken and the Woodford, but how do you guys think about your limit, or what's the limit to current allocation of capital into these plays and maybe you could discuss that, if you would, please?

Yes, I don't think we're there. I think what we, what we would say is we, probably from the circa 2009-2010 area on the unconventionals, we would probably throw in $0.5 billion a year at this. We're going to be closer to $1 billion. And I believe that we have room to increase that by another 50%. The real key for us is in all these plays, is to make sure that our internal systems with the number of people, professionals we have, can manage the business effectively and we're going to be very comfortably moving to 20 rigs and, again, I think we could go to 30, which exposes us, the potential to move into another one of these plays pretty readily.

Okay. That's, that's helpful. And then, a little bit of a follow-up on the downstream and some of the comments on availing lesser expensive crudes, whether it's TI or, or other heavies. And I know that you guys own a lot of Mid-Con infrastructure. How do you, how do you see the imbalances from growing production stream into the Mid-Con balancing and potentially benefiting? Do you think, before new take-away capacity or before Keystone gets to the Gulf Coast that you'll see continued pressure, meaning lesser expensive feed stock for Marathon for the next several years and then a bit more of a detailed follow-on, how much crude are you guys able to barge down, so that it might displace LSS runs in Garyville, if you can quantify that.

Sure, Evan. First question, you know, I think you hit it right on the head. The -- until you get new major take-away capacity possibly into the Gulf Coast, whether it's the Houston Corridor, the Louisiana Corridor of refining or maybe both, but until you get that, I think you're going to be bottle-necked in pad 2 and possibly in the, you know, upper west side of pad 2. And I think it's going to be for quite sometime. I think it remains to be seen, you know, possibly later this year on where the state department will come down on a new pipeline into the Gulf Coast. We're not a party to that transportation system, so I'm not privy to all the detail.

But, you know, when you look at incremental Canadian coming down and then you look at all of the incremental Bakken crudes and the gap is pretty wide on when you look at the production forecast on Bakken, there are some unit trains that are taking some crude into different markets, but, you know, I see a lot of that crude landing in the Patoka, Wood River arena, and as you said earlier, we are very advantaged with our logistics system in and around that market, that we can take advantage and get that into our system.

You know, here again, with Detroit coming on stream in 2012 and having the infrastructure, we are having some infrastructure built or modified in order to be able to get some additional Canadian heavy into that stream. I think we're going to be very, very well positioned. But I still believe it's probably the latter part of the decade at the earliest, until you see a system actually, built and functioning to get heavy crudes into the Gulf Coast. Yes, we do move some barrels down to Garyville from time to time, depending on the differentials, and while I can't give you the exact number from a competitive nature, I don't want to get that number out, Evan. I can say that we take every advantage we can of moving those crudes down into the Garyville market.

Do you think any of those crudes out of Cushing can back up at reduced volumes on Capline, kind of going through Pagoda?

Oh, the Capline has already been reduced. Capline has really turned into an LLS, basically Mars system. Some imported cargoes come through a little bit into Capline, but the barrels that come into Cushing, and if you look at the maps on how you export out of Cushing into the markets, so if you really are going to go east and hit the pad 2 market, there's one major pipeline system and it has a rate of capacity of about 220,000 barrels per day. It's the companies that have the allocated space and have the historical shipping pattern that are able to take advantage of those crude and get them out and I will say Marathon has a very nice position in historical shipping space.

Great. Thank you very much.

You're welcome.

Your next question comes from Paul Cheng of Barclays Capital. Please go ahead.

Thank you. When we're looking at oil sands, given now that you're going to spin the company into two and so there's really no integration with refining anymore, so how important is the oil sand to the future of the company, and given that -- seems like the Chinese may be willing to pay a very high price for that kind of asset, is it important for you to continue?

You know, Paul, we've said all along it's a very substantial secure North America resource that, you know, as we build up here to 45,000, 50,000 barrels a day of capacity, has very little decline to it. And given what we see as upside in oil price over the long-term, we think it's a good asset for our portfolio that provides that stable, steady inflow of cash flow and earnings sent to the company for reinvestment. And again, gives us the opportunity to grow in the future. You're right, the integration is not there in large part because most of the near-term growth we're going to have at AOSP is going to generate synthetic crude, not bitumen, but down the road, we certainly see the opportunity to expand beyond where we are, I think as we talked about, the ultimate asset has a growth potential of some 750,000 barrels a day and certainly our 20% share makes that a very significant asset. So we see it as having a key role going forward.

Okay. Dave, on Bakken, what's the exit rate for the year? For 2010?

About 15,000 barrels a day, Paul. About 15,000 BOE D.

Okay.

Paul, on Slide 19, it talks about the exit rate in Bakken going from about 15,000 in 2010 to over 18,000 in 2011.

Right. So with the exit rate for 2011 would be 18,000.

Something over 18,000.

Given you are already at 15,000 and by the end of the year, you get to about 18,000 19,000, have you guys re-looked at your portfolio, and looking at your land position and would that lead you to revise saying that your 22,000-barrel per day target may be just a bit too conservative, or that you still think based on the asset portfolio that you have over there that this is reasonably correct?

Well, Paul, I think there's probably two thought lines in there. Number one, I do think that we have a tendency to not be conservative, but be very carefully technically, and this is our current technical judgment. We do clearly understand there's differences with other people and their portfolio and we continue to look at that. And as conditions change and as we learn things from other operators in the field, we may indeed look at increasing our expectations. But right now, it's a very good business. We're very happy with it, and we certainly see more upside than downside.

Thank you.

Thanks, Paul.

The next question comes from Jeff Dietert of Simmons and Co. Please go ahead.

Good afternoon.

Hi, Jeff.

In the interest of a very balanced call, I've got a question for Dave and one for Gary. Dave, you provided some good information as far as the number of wells you plan to drill, operated wells, and I think you mentioned 60% average interest there, and a number of wells operated by others with 15% interest there. Still, as I try to model out that level of drilling activity and I look at the growth from 15,000 barrels a day to something above 18,000 barrels a day in 2011 in the Bakken, the 18,000 looks conservative. Could you provide some color there? Is this program back end loaded? Do you expect to complete a number of the wells later in the year, or can you help me with that?

Yes. First of all, just some clarity. When we talk about a 60% co-op interest and 50% OBO, we're speaking about the Woodford. And I'm quite sure that I probably misstated the wells. We'll drill at least 20 company-operated wells with upside of 30-plus, and in the range on OBO will be 30% to 50%. So that's the Woodford side of things. And that's where we have three rigs operating presently and are moving to eight by the end of the year. So the rest of your question with Bakken, we have a very high working interest percentage on the Bakken and we will probably drill on the order of 70 wells in addition to the 200 that we already have in the play up there. And we typically carry greater than 80% working interest. We'll drill that many, 70 number, on an outside operated basis, but those are typically very small interest, because of the way the play is segregated. And again, I think what we continue to see is we continue to give guidance. It takes about 25 days to drill one of these wells. We are moving in a rig that's going to do nothing but completions. This year, we are going to add a dedicated frack crew to our business, because it's going to shorten the cycle time in terms of spuds to frack. But even given all those numbers, the way we bring wells on in terms of trying to manage the drawdown and developing our IP rate, we think that's a very consistent way to look at this in terms of, say, 14,700 barrels a day, which is essentially what we're running today, assuming those people haven't frozen to death up there, to a little over 18,000 on an exit rate. It could get better, because we are moving into stronger areas of the play, in terms of what we think the EURs are, but I also -- I'm not sand bagging you here either with the way we ultimately are developing the play.

Very good. Thanks for the clarification, and the additional color. Gary, as you look at some of the crudes, going back to Gulf Coast with LLS trading $12.50 premium to WTI and Mars, over $6 over WTI, are there adjustments in place that the industry is likely to make, given that this happened so quickly to reduce those premiums? Or do you think those premiums hold and perhaps even expand as the mid-continent drilling continues to ramp up and the Gulf of Mexico drilling is hampered by regulatory issues?

Well, kind of going back to one of the comments I made earlier, if you look at some of the mid-continent crudes that are, you know, probably more market locked today because of take-away capacity, yes, the industry is looking at a unit trains and I know there are some lateral pipelines being considered to tie into some of the main lines as well. You know, back to the first part of your question, when you look at LLS and Mars, yes, absolutely, it's very expensive crude versus WTI.

But WTI is not a very big market to begin with, and so, every day when you look at them, excuse me, those crudes that are available that you run, certainly based on your infrastructure are going to fill up on all the WTI reference type crudes first and, you know, Canadian reference type crudes that your infrastructure will allow, but, to be very honest, then you're left with LLS, Mars, and some foreign cargoes, and you're constantly looking at the yields and looking at the alternative price.

What the industry can do, I really believe you're going to continue to see this dislocation somewhat, or inversion if you want to call it, like I answered earlier, until you get some more take-away capacity in place, because certainly as Dave has mentioned from the upstream side, those crudes are going to continue to be developed and produced, as well as new production coming on in Canada.

So I think bottom line to your question, I believe it puts us into a very good position in order to be able to, with our infrastructure, have a fairly decent allocation of pipeline space to run some of those crudes. But LLS and Mars are still going to come up Capline and be your next alternative crude.

Just given the economics, it seems like people would shift away from Capline crudes to the extent they could.

You're absolutely right, Jeff, and that's what I was trying to say. We're switching away as much as you can from Capline based crudes, but as I said earlier, out of Cushing, there's 220,000 barrels a day is what the Ozark pipeline is rated. I think it's rated a little bit higher, but nominally, it's running about 220,000, 225,000 today. Once you get beyond that, the Canadian company down, you're left with, you know, Capline based crudes.

Very good. Thank you.

Thanks, Jeff.

Our next question comes from Arjun Murti of Goldman Sachs. Please go ahead.

Thank you. My question was on how you view the kind of scale and competitiveness of your US shale position, especially as you integrate and increasingly get compared to some of the large and midsize independents out there. You obviously have a very nice position in the Bakken. Your position in some of these other plays, you know, you're growing, but they generally look smaller. Do you believe you can continue on with this, I guess, incremental approach to adding acreage, or at some point will you have to take a bigger step, whether it's an acquisition or a more meaningful joint venture to really scale up in US shale? Thank you.

Arjun, I guess we put out a slide, I think it may have been in the materials when we discussed the separation we had that conference call, that showed our acreage position in the liquids-rich resource plays. And I think we ought to distinguish between that. We don't count in there the acreage we got in Marcellus or Haynesville or others. Our focus is specific to the liquids-rich resource plays and certainly the four that Dave has talked about here today.

So I think when you look at that competitive comparison as we sit today, we're actually in pretty good shape relative to our E&P peer universe, and indeed, we've already increased beyond what we showed from that time, and as Dave said, we continue to increase that. We certainly are, and I think as I referred to when I talked about uses of cash, we certainly are looking at other opportunities that would give us an opportunity to effect a step change in our position in some of the key plays, but again, I think it's important to look at where we are and where we're going with respect to the liquids-rich resource plays at this stage, we will maintain the future optionality on our gas-rich plays, but we have no intent of pursuing those or spending much money on them at this time.

Thank you very much. I appreciate your answer, Clarence. Just for the second question, can you just talk about the Poland plants for this year and should we think about this year as mostly a science experiment type year, or is there a chance you can actually get enough comfort in what you've drilled to move forward more meaningfully if you did meet with success there?

Well, it's a 2.5 million-acre play, and if we're really good this year, we'll get one or two wells down. So I think the answer to your question is the former. We got a lot of work to do. Each one of these blocks, you'll remember, is close to quarter of a million acres. Even if you get one well in them, you'll have one well in the quarter of a million acres, which is the size of what you say some of our competitors have in these unconventional plays in the United States. So a lot more work to do.

That's great. Thank you very much.

Thanks, Arjun.

Next question comes from Blake Fernandez of Howard Weil.

Good afternoon, guys. Thanks for taking my question. First one is a little bit more detailed, but it is on the corporate and unallocated income tax line item. It looks like it's up about $300 billion year-over-year. I'm just trying to get a sense of what that should look like going into next year.

I think you know there's a lot that goes into that line that gets compressed. As you know, when we're booking income taxes, we estimate what the effective tax rate will be for the full year and book to that. And you know that our income is from tax jurisdictions with wildly different tax rates. Everything from 25% to 93%. So, as we get through the year and the mix changes, our expectation of the full year effective tax rate also changes.

What happened this year in the fourth quarter, was that the mix had changed to a lower tax jurisdiction and effectively we had been over-booking taxes the first nine months and we had to adjust in the fourth quarter so that for the full year, we had the accurate effective tax rate. I think last year we might have had some pretty significant FX adjustments on our deferred taxes and as you know, we saw the biggest portion of that by converting our deferred tax liability in Canada to US dollars. So we don't have that noise in the numbers anymore.

So Janet, just so I understand going forward though, it seems like maybe you shift your assumption on tax going into '11? Therefore the number should be more kind of a lower level than '10?

No, I think you're faced with essentially the same issue every year, this uncertainty about where you're going to generate your income. And therefore what the mix will be and therefore what the effective tax rate will be.

Got it, okay, thank you. And then the second question was on the downstream. Gary, you mentioned the new docks and ability to export. I was just curious if you could give us some order of magnitude on what percentage of your total sales are actually being exported? And then additionally, if you had any color on actually what percentage of your throughput is actually coming from Cushing or running WTI?

Right. As far as the percentage of exports of total would be very small. The key number that I spoke to earlier, we have about 40% take-away capacity of Garyville. So, you know, if Garyville has, you know, let's call it 460,000 barrels a day and as I look at about 40%, it's not over just the new dock. It's over all the other docks we have as well. We have about 40% take-away capacity on the dock and then we take a tremendous amount of the pipelines, both Plantation and Colonial pipeline. So what we're exporting is, you know, as I said, Europe, South America, Latin America, and then we're also the largest supplier of bulk business into Florida. And the second?

If you could clarify what percentage of your throughputs are actually running on WTI.

Okay. If I look at, you know, WTI reference crudes, about 20% is what I would call reference crudes, WTI.

Great. Appreciate it.

That's last quarter.

Okay, thank you.

Our next question comes from Paul Sankey of Deutsche Bank.

Hi, guys, good afternoon. My question is actually an expansion of Arjun's first question regarding your competitive position as a stand-alone upstream E&P company. Beyond the 2011, I was really wondering, Clarence, the level of growth you'll be targeting to remain competitive with that group, which typically has obviously shown a higher rate of growth than integrated oils and I wonder if you could just speak a little bit to that balance between growth and returns and how you'll see it once you're in that peer group, if you will. Thanks.

Yes, I think, Paul, while the peer group may change, our focus is going to remain on profitability and returns. And so to a certain extent, that will likely mean a lower rate of growth than some of our peers. I would also say, though, that, again, just as we talked about the acreage, I think we need to look at production the same way and I would suggest that our growth in liquids will be very competitive with our peers.

Again, we're not going to chase natural gas. We're in a fortunate position that where we have our gas resource for the most part, it is held by production, and we can wait until we see better prices and better economics before beginning to invest in that. So while we will probably target, as we've said before, the 3% to 5% production growth, that may not compare with those that are double digit, but again, our view is a more sustainable level of lower risk growth focused on liquids, is the best way for us to create value for our shareholders.

Absolutely. And then obviously we'll be able to look at return on capital employed, premium return on capital employed as the outcome of that strategy.

Correct.

And then briefly, Gary, you mentioned, quickly, the theme of one upstream and one downstream, you mentioned on page 15 some of the costs to date that actually didn't go there on the sweet sour for you guys. Could you just talk a little bit about given that that was what you said was the main, most important thing, if you could just kind of give us a number, that would be great. Thanks.

And, Paul, I have the numbers on the crack spread month to date. I'm sorry. I just don't have the whole book of all the different crudes that we have purchased to date to give you the sweet sour on an average basis and date. Gary, do you have --

I'm sorry, Paul.

Sweet sour for the month of January.

For January?

Do you have the sweet sour, what it averaged for the month of January? I don't have it with me.

I think it's somewhere in the neighborhood of about $9.50 a barrel we would guesstimate for the month of January on our basket.

Great. Do you know where it is right now?

No I don't not at the moment, no.

Fair enough. I'll leave it there. Thank you, guys.

The next question comes from Kate Minyard of JP Morgan.

Hi, good afternoon. Just two quick questions. First of all, on the CapEx release, if I strip out the DHOUP project from downstream, it looks as though the downstream maintenance CapEx level is just a little bit lower than what you guys had previously guided toward as a run rate. So I was just wondering if there's a certain lumpiness to downstream CapEx, maintenance CapEx, or how we should be thinking about that going forward? And then just the second question is you guys gave a reserve bookings estimate. I was just wondering if you also could give a rough F&D number on that. Thanks.

This is Garry Peiffer. The downstream CapEx, I think you were referring to the fact that we set our maintenance, our sustaining capital is in the $700 million to $800 million range and obviously everything that's left over after DHOUP is a little bit less than that.

Right.

I think we've kind of trimmed back on those other sustaining, if you will, or maintenance type of things to accommodate the big spend on DHOUP. So there is a bit of lumpiness to it, but we're just trying to maintain a fairly disciplined capital program here in 2011. So we would still say going forward that our sustaining capital, maintenance capital is in that $700 million to $800 million range.

Okay, thanks.

Kate, on the F&D, we'll be coming out with a more fulsome release in a couple weeks on the total reserve replacement picture and that will be included in that also.

Okay. Thanks a lot.

The next question comes from Mark Gilman of the Benchmark Security.

Hi, guys. Two quick ones for Dave, if I could, please. Dave, overall decline rate, overall average decline rate, the base CapEx 2011 looks like up about a third versus '10. You know, have, as a result of that, have you reduced your expectations regarding decline rate, and what decline rate's implicit in the 2011 production guidance?

Okay, Mark. I think there's a -- we continue to point towards this ability of the overall business to maintain 5% to 7% decline rate with investment. And I think if you break it down, the US business is essentially going to be flat to inclining this year and the forward business has minimal decline as well. So I still think 6% is the number that we like in terms of the aggregate, and, remember, what we talked about in our guidance is we think the base that we have now is substantially below that and a lot of the declines we have are featured in these growth assets because the unconventionals have pretty aggressive upfront decline.

Okay, Dave, and one more if I could. You made reference to the seven discoveries in Libya. Could you talk a little bit about what the production potential of those discoveries is, and whether they are subject to exit terms or the more conventional and traditional tax concession arrangement?

We are not subject to EFSA conditions. All of the 13 million acres that we have in our concession are subject to the fixed earnings contract that we have. I would say one of the things that we've been able to influence since we've been in the chair as the head of the 2P group is we've been able to emphasize larger exploration targets and those that have the ability to be connected more quickly. I will say that of the seven discoveries, one of the things we're very pleased with, even though they are modest in terms of their production capacity against the 360,000 barrels a day that we're producing, one of them will actually be hooked up within the same year it was drilled, which we feel very good about. And another one is essentially an extension of one of the major developed projects that we will likely embark on in the next couple of years over there. So positive movement in terms of some of the things that we look at for businesses outside of that environment, and generally still encouraged about the direction we're going in Libya.

If I could just sneak in one more detail, your US gas price, natural gas price realization on the quarter seemed very much out of line with the past and with the midweek marker. Is there something in there we should be aware of?

Not, not that we're aware of, Mark. Looking out, there's nothing that strikes us. Let us look at that and we'll get back to you.

Okay, that would be great. Thanks very much.

Thanks, Mark.

Your next question comes from Pavel Molchanov of Raymond James.

Okay, thanks. One upstream, one downstream for me as well. On the DD&A side, you mentioned Droshky of course, affected the numbers for the past few quarters. How should we think about DD&A heading into Q1 and the rest of the year?

Well, Pavel, was that question specifically for Droshky?

Just for the E&P business overall.

Well, I think it's probably easier for me to focus in on the Droshky issue because I think that's what we've guided to, and then I'll ponder the other a little bit. We basically expect Droshky, the DD&A tax rate to increase. Last year, we would have seen on the order of $60 to $65 a barrel. This year, we'll guide towards $80 to $90 as we go through more declines and focus on installing the water flow to make sure that we get the actual reserves out of the program. Last year, what we guided to was, was on the order of mid 13's for the entire business and I don't see that going up. We were talking about a range of DD&A for the aggregate upstream business of between $14 and $17.

Okay, and for the segment as a whole, any thoughts on that?

I think that's -- I'm sorry. That's what I just mentioned.

Okay.

Between $14 and $17.

Okay, okay. Perfect. Then on the downstream side, actually kind of a hypothetical, if I may. If you had decided to do the spin-off, let's say six months or nine months earlier, would you have still sold Minnesota?

Yes, that has been our long-term strategy and the market in late '08, we were talking about this. I think there have been some hint of, you know, some asset sales back in '08. And the market turned such that it was very difficult from a credit standpoint to be able to get that transaction complete. But we've been working on this sometime and this was part of our overall strategy when we elected to move forward with Detroit, that we were going to exit the St. Paul Park market.

All right. Appreciate the color. Thanks.

Our next question is a follow-up question from Paul Cheng of Barclays Capital.

Thank you. Gary, in the downstream, how much do you run as a WTI and Canadian reference crew? I mean, you are talking about the 20% for WTI. So when we are looking at your light sweet or sweet and sour spread, what is the percent of your crude slate will be effected by that? Is it 50%, 60%, or any other number?

No, it would be less than 10%.

No, I mean in terms of your crude slate on the sweet and sour defense? Only 10% of your crew will benefit from the widening there?

Oh, I--

Higher than that?

Paul, the way we calculate it in our basket that's out there is it's only 15% of that basket is western Canadian.

No, no, I understand, Gary. I was talking about that -- in the first quarter, you are saying that spread may be up, say, based on you're saying to about $9.50, so to about $0.80. Should we assume your margin rate will have, say, a 50% benefit of that $0.80 or 60%, or how much of that should we assume? So if the sweet and sour defense improves a dollar per barrel, does that translate into $0.50 per barrel improvement in your realized margin, or--

On an annualized basis, Paul, after tax, every dollar change in that basket approaches about $150 million.

After tax.

After tax.

Okay. So annual, okay.

Annually, yes.

We can do that calculation on that right there.

Right.

And, Gary, on the contango market, is it 55% to 60% of your crew crude purchase will be impacted by the contango market or less?

Let's see here. It's probably closer to about 75%.

75% of all your crudes will be impacted by contango market?

Yes, sir. That's what it was last quarter. It varies obviously with the crude slates, but that's about the right number. About 75%.

I see, and then for Dave, for the Woodford, you're saying that you expect the exit rate to be over 7000-barrel per day. Do you have a longer term target and also that maybe three of four years down the road, what is your expectation for all your conventional shell oil expectation?

Yes, Paul, we've not settled on a target for the Woodford yet, a long-term that we're willing to publish, but just generally shorthand, we want all these businesses to be about 25,000 barrels a day minimum.

(Inaudible) basin?

So like the Woodford, we think has the capability to do on the order of 30,000. It's way too early in our programs in the Eagle Ford and the Niobrara and we're still sticking with the 22,000 plus that we have in the box.

Okay, I see. Thank you.

(Operator Instructions)

The next question comes from Doug Leggate of Bank of America Merrill Lynch.

Thanks. Apologies for the follow-up folks. I wanted to try a question I guess I tried a couple weeks ago at Dave. Kurdistan, our understanding is that ShaMaran reported pretty good results in the Atrush well and I wonder if you could give some color as to how you see that and what the likely timing is for maybe getting a result there. My second question of my two, I guess, second time around, very quickly, on the oil sands, can you just give us an idea what the run rate costs will be once all these one-off costs and so on, are done so we get an idea of what the go-forward margins should be in the business? Thanks.

We expect the cash operating costs on a go-forward basis to return what they were, were in the range of 2009 at $35. $35, $40 a barrel. Last year they popped up to $63, largely because of the turnaround, and we expect and we get the additional volumes on, that we'll get back into those ranges. And that's certainly where we're targeting as a consortium and I know shell's still looking at driving the costs down from that. On the other, Doug, all I can tell you is our people are literally meeting with the minister right now. We continue to be encouraged with what we've seen on the drilling results and we will get the results out to folks just as soon as we can.

All right. Thanks, Dave. Thanks.

We have no further questions at this time. Mr. Thill, would you like to make any closing remarks?

Thanks, Monica. We appreciate it. We appreciate everyone's attendance at today's conference and we're looking forward to visiting with you in the near future. Have a great day.

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