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Executives

Gary Heminger - Executive Vice President of Downstream and President of Marathon Ashland Petroleum LLC

Clarence Cazalot - Chief Executive Officer, President, Director and Member of Proxy Committee

Howard Thill - Vice President of Investor Relations & Public Affairs

David Roberts - Executive Vice President of Upstream

Janet Clark - Chief Financial Officer, Executive Vice President and Member of Proxy Committee

Analysts

Edward Westlake - Crédit Suisse AG

Katherine Minyard

Jeffrey A. Dietert

Douglas Terreson - ISI Group Inc.

Evan Calio - Morgan Stanley

Pavel Molchanov - Raymond James & Associates

Mark Gilman - The Benchmark Company, LLC

Paul Cheng

Arjun Murti - Goldman Sachs Group Inc.

Faisel Khan - Citigroup Inc

Douglas Leggate - BofA Merrill Lynch

Paul Sankey - Deutsche Bank AG

Blake Fernandez - Howard Weil Incorporated

Marathon Oil (MRO) Q4 2010 Earnings Call February 2, 2011 2:00 PM ET

Operator

Welcome to the Marathon Oil Corporation Fourth Quarter and Full Year 2010 Earnings Conference Call. My name is Monica, and I'll be your operator for today's conference. [Operator Instructions] I will now turn the call over to Howard Thill, Marathon Vice President, Investor Relations and Public Affairs. Mr. Thill, you may begin.

Howard Thill

Thanks Monica. And I, too, would like to welcome you to Marathon Oil Corporation's Fourth Quarter 2010 Earnings Webcast and Teleconference. The synchronized slides of the company in 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 Garry 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 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-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 rates 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 [Exploration and Production] and Downstream businesses, partially offset by higher income taxes and lower earnings in our Oil Sands Mining [OSM] segment.

As shown on Slide 7, E&P segment income was slightly lower for the fourth quarter compared to the third quarter of 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 [barrels of oil equivalent] increased $6, while NYMEX prompt WTI [West Texas Intermediate] increased $9 per barrel and the bid week natural gas price decreased $0.58 per MMBTU [Million Metric British Thermal Units].

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 and underlift in Europe of about 700,000 BOE in both EG [Equatorial Guinea] and Libya being underlifted by approximately 300,000 BOE. Fourth quarter 2010 production available for sale increased 3% 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 costs 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 cost per BOE is largely a result of work-over 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 results.

Turning to Slide 12. In Oil Sands Mining, fourth quarter segment income was $9 million, which reflects both positive price and volume variances over the third quarter, offset by onetime start-up and ongoing costs at the Jackpine Mine, an increase blend stock volumes and costs. Net synthetic crude sales for the quarter increased 38,000 barrels per day as production continue 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.

David Roberts

Thanks, Howard. Despite significant challenges in 2010, the Upstream business continued on the 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 stands 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 in sight on new opportunity to increase that position to over 100,000 acres shortly. Importantly, we will have eight 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 we'll likely expand that position further in 2011. And we built a 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 for two- and one-rig programs, respectively, to begin with and a capability to expand this condition as warranted.

Internationally, we built our position in Poland to over 2 million acres, and we'll 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 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 operating activity on two 100% blocks throughout this year. A key driver for 2011 performance began to debut in 2010 as the Jackpine Mine commenced start-up in the third quarter. The upgrader for the project is currently in start-up 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're focused on two things that will make us successful in the future. The first is disciplined investment 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 turnaround flawlessly in 2010, and we had, overall, 94% operational reliability across our operated assets. High reliability yield is our most cost-effective and 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.

Howard Thill

Thanks, Dave. Moving to our Downstream results in Slide 14. RM&T's [Refining, Marketing and Transportation] 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 feedstock costs were lower than the change in the average price of LLS [Light Louisiana Sweet] 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 processed through our refinery 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 of 2009, which also reduced our actual crude cost 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 crack unit, also improved results over the fourth quarter of 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 [SSA] refined product and merchandise gross margin was about $16 million higher in the fourth quarter 2010 compared to the fourth quarter of 2009. The increase was primarily due to higher gasoline and distillate margins, which increased from $0.10 per gallon in the fourth quarter of 2009 to $0.14 per gallon in the fourth quarter of 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 6-3-2-1 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.

Gary Heminger

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 U.S. 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 [DHOUP] 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 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 takeaway capacity by approximately 40%. This dock, in conjunction with the additional barrels of distillate produce, 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 start-up in the second half of 2012. 25% of the construction is complete, and we plan 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 U.S. 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.

Howard Thill

Thanks, Gary. Slide 17 provides an analysis of total company preliminary cash flows for the year of 2010. Operating cash flow from continuing operations before changes and 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 the 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. And a reminder, this debt includes approximately $198 million, which is serviced by U.S. 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.

Clarence Cazalot

Thank you, Howard. Let me begin with the overriding corporate priority, which is to affect 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 upfront 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 have spin for a [ph] very strong balance sheet. That's our highest priority for cash. Secondly, as we have 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 has been, 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.

Howard Thill

Thanks, Clarence. [Operator Instructions] And Monica, with that, we'll turn it over to you for taking the calls.

Question-and-Answer Session

Operator

[Operator Instructions] The first question comes from Doug Terreson of ISI.

Douglas Terreson - ISI Group Inc.

First, Libya is a fairly relevant E&P position for the company. And I want to see whether you guys have had any operational changes related to the security situation in North Africa, and also how you perceive the geopolitical threat in the country, if you think it's meaningful.

David Roberts

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've 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 as 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 running.

Douglas Terreson - ISI Group Inc.

And also I had a question for Gary. Refining and Marketing earnings would have been stronger absent the $66-million negative item, and so I want 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.

Gary Heminger

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

Garry Peiffer

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, it's 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 over operations.

Gary Heminger

And, Doug, looking at the crack spreads on Page 15 that you're asking about, 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 differential because of some advantage markets, that we are in. Basically, the Canadian markets and some of the West Texas Intermediate proves that we can move to 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 that Chicago has been basically less than $1. $0.69, Garry says. Do you have the Gulf Coast? $2.18 month-to-date in the Gulf Coast.

Garry Peiffer

That's for January. That's just January.

Operator

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

Douglas Leggate - BofA Merrill Lynch

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 Woodford I understand you have fairly' material non-operated positions. And if I'm not mistaken, your partners are ramping up the rig count pretty dramatically. So the outlook there, please. If you could 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? So we're hearing that basically you've moved to a little bit more aggressive frac stages. And I have a follow-up for Garry.

David Roberts

I'll 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 areas that we're moving into right now, where we are actually pumping higher stages in the 15 to 20 stage range. But I don't think that, that signal necessarily a shift to us going to that. We basically let the wells in the reservoir tell us what it is that we're going to need to do there as far as that goes. Droshky question, Q4, we had 31,000 barrels 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 still very strong rate at the present time. With respect to the question in 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 we'll probably get on the order of 12, 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 30 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 OBO [operated by others] basis, about 15%. So most of the activity that drives our production is going to come from stuff that we do.

Douglas Leggate - BofA Merrill Lynch

Gary, you said, I guess, often about Texas City perhaps being a challenged asset. The other day, BP [British Petroleum] has announced that they are selling Texas City in its won right. Do you see any potential scope for being interested in the asset and perhaps addressing the structural weakness in your facility down there and how we get there?

Gary Heminger

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

Operator

Our next question comes from Edward Westlake of Credit Suisse.

Edward Westlake - Crédit Suisse AG

Maybe a first question for Gary on the Downstream. Obviously, 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?

Gary Heminger

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% and 8%, depending on the type of crudes and the yield to get out of those crudes. But everyday, we are optimizing our crude slate to be able to take advantage of what has gasoline, diesel or some of our other process units to get the best and the most profitable yields. But it's pretty much in the, I'd say, 8% to 10% category. It's how we can move, and 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 in an advantaged price versus alternative crudes, we certainly, everyday, take advantage of those.

Edward Westlake - Crédit Suisse AG

Is there any trend that you can talk to in terms of the amounts of some of these cheap inland crude that you've been able to capture or costs in terms of producing their operating costs?

Gary Heminger

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. Until we finish our Detroit project -- if you could wish, I'd 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 whatever is all going to be based on the amount of infrastructure that you can move crudes through.

Garry Peiffer

And this is Garry Peiffer. Just one other item on the distillate. I think you have seen 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 distillates production, which based upon just crude oil inputs rather than total input. 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.

Gary Heminger

And, Ed, when we built Garyville, our plan was to try to do approximately 50-50 distillates and then gasoline and other components.

Edward Westlake - Crédit Suisse AG

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

David Roberts

I think that most of the kit will be up and running full stream by the end of the quarter. The real key is the residual hydrocracker, which will give us full capacity on the upgrader, probably will drift into April, would be my guess. So end of the first quarter, end of April, for sure.

Operator

The next question comes from Faisel Khan of Citi.

Faisel Khan - Citigroup Inc

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've got the asset sale in December in there. But how much of working capital gain was there sequentially, third quarter to fourth quarter?

Janet Clark

In the fourth quarter, we had just over $1 billion, I think, of cash provided from working capital. Let me doublecheck that for you Faisel.

Faisel Khan - Citigroup Inc

And then just on the Canadian -- the Oil Sands business. You guys talked about, I guess, the higher start-up cost, 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 hydrocracker wasn't available?

David Roberts

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

Faisel Khan - Citigroup Inc

The way your LNG [liquefied natural gas] contract works at BG, is that a fixed amount of volume every quarter? How much excess LNG capacity you have to sell into the spot market?

David Roberts

Any volume that we have is committed to BG.

Operator

The next question comes from Evan Calio of Morgan Stanley.

Evan Calio - Morgan Stanley

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 to the increase granularity on CapEx and volume outlook on the Bakken and the Woodford, how do you guys think about your limit or what's the limit to current allocation of capital into these plays? And maybe if you could discuss that if you would please.

David Roberts

I don't think we're there. I think what we would say is probably from the circuit 2009, 2010 area, the unconventionals, we will probably throw in $500 billion a year at this. We are 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 of these plays, is to make sure that our internal systems with the number of people, professionals we have, it can manage the business effectively. And we are going to be very comfortable moving 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.

Evan Calio - Morgan Stanley

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 other heavies. And I know that you guys own a lot of mid-con [mid-continental] infrastructure. How do you see the imbalances from growing production stream into the mid-con balancing and potentially benefiting? Do you think before we takeaway capacity or before Keystone gets to the Gulf Coast that you'll see continued pressure, meaning lesser expensive feedstock from Marathon for the next several years and then a bit of -- more of a detailed follow-on. How much crude are you guys able to barge down so that -- that may displace [indiscernible] runs in Garyville. Can you quantify that?

Gary Heminger

First question, I think you hit it right on the head. Until you get new major takeaway capacity possibly into the Gulf Coast, whether it's the Houston corridor or the Louisiana corridor of refining or maybe both, but until you get that I think you're going to be in a bottleneck in PAD II and possibly in the upper West side of PAD II. And I think some are going to be for quite some time. I think it remains to be seen possibly later this year on where the State Department will come down on the new pipeline into the Gulf Coast. We now have parties to that transportation system so I am not privy to all the details. But when you look at incremental Canadian coming down and then you look at all of the incremental Bakken crudes, then the gap is pretty wide on when you look at production forecast on Bakken. There are some unit trains that are taking some crude into different markets. But 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. 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 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 can we take every advantage we can of moving those crudes down into the the Garyville market.

Arjun Murti - Goldman Sachs Group Inc.

Do you think those crudes out of Cushing can back up it, reduce volumes on Capline kind of going through Pagoda [ph]?

Gary Heminger

The Capline has already been reduced. Capline has really turned into an LLS basically MAR systems. Some imported cargoes come through a loop then into Capline. But the barrels come in to Cushing and if you look at the maps on how you export out of Cushing into the markets, so if you're really going to go East and hit the PAD II market, there's one major pipeline system. And it has a rating capacity of about 220,000 barrels per day. So 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.

Operator

Our next question comes from Paul Cheng of Barclays Capital.

Paul Cheng

Clarence, when we're looking at oil sands, given now that you're going to spin the company into two and so that's really no integration with the refining anymore. So how important is the oil sand to the future of the company? And given that since that the chinese might be willing to pay a very high price for that kind of asset, is it important for you to continue to keep it?

Clarence Cazalot

Paul, we've said all along, it's a very substantial, secure North America resource that 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 us is an upside in oil price over the long term, we think it's a good asset for our portfolio that provide that stable steady inflow of cash flow and earnings 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 -- 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 gross potential of some 750,000 barrels a day. Certainly, our 20% share makes that a very significant asset. So we see it as having a key role going forward.

Paul Cheng

Based on Bakken, what's the exit rate for the year? For 2010?

David Roberts

About 15,000 barrels a day, Paul. About 15,000 boepd.

Clarence Cazalot

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

Paul Cheng

So the exit rate for 2011 would be 18,000?

Clarence Cazalot

Some over 18,000.

Paul Cheng

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

David Roberts

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 in their portfolio and we continue to look at that. And as conditions change and as we learn or learn things from the 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.

Operator

The next question comes from Jeff Dietert of Simmons & Company.

Jeffrey A. Dietert

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. In 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?

David Roberts

Yes. First of all, just some clarity. When we talk about a 60% co-op interest and 50% OBO is 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 then 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. The rest of your question, with Bakken, we have a very high working interest percentage on the Bakken. We will probably drill on the order of 70 wells in addition to the 200 that we already have in the play out there. And we typically carry greater than 80% working interest. We'll drill that 70 number on an upside 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 frac crew to our business. This is going to shorten the cycle time in terms of spread of the frac. But even given all those numbers, the way we bring wells on in terms of trying to manage the drawdown in developing our IP rate, we think that the very consistent way to look at this from say 14,700 barrels a day which is essentially what we are running today, assuming the people have been frozen to death up there, it's a little over 18,000 on an exit rate. So it could get better because we are moving in to stronger areas of the play in terms of what we think the EURs are. But I'm not sandbagging you here either with the way we ultimately are developing the play.

Jeffrey A. Dietert

Gary, as you look at some of the crudes going back to the Gulf Coast, with LLS trading $12.50 premium to WTI and Mars over $6 over WTI. Are there adjustments in plays 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.

Gary Heminger

Well kind of going back to one of the comments I made earlier, if you look at some of the mid-con crudes that are probably more market locked today because of takeaway capacity, yes, the industry is looking at unit trains and I know there is some lateral pipelines that are being considered to tie in to some of the main lines as well. Back to the first part of your question, when you look at LLS and Mars, and yes, absolutely it's very expensive crude versus WTI. But WTI is not a very big market to begin with. And everyday when you look at those crudes that are available that you run, certainly based on your infrastructure, you're going to fill up all the WTI-referenced-type crudes first and Canadian-referenced-type crudes that the 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. So what the industry can do, I really believe that you're going to continue see this dislocation somewhat or aversion if you want to call it like I had answered earlier, until you get some more takeaway capacity in place. Because certainly as Dave has mentioned from the upstream side, those crudes kind of 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. But LLS and Mars are still going to come up Capline and be your next alternative crude.

Jeffrey A. Dietert

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

Gary Heminger

You're absolutely right, Jeff. 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 this pipeline is rated. Or I think it is rated a little bit higher, but normally it's running about 220,000, 225,000 a day. So once you get beyond that, and the Canadian coming down, you're left with Capline-based crudes.

Operator

Our next question comes from Arjun Murti of Goldman Sachs.

Arjun Murti - Goldman Sachs Group Inc.

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

Clarence Cazalot

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 are 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 affect the 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 are 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 it at this time.

Arjun Murti - Goldman Sachs Group Inc.

Just for the second question, can you just talk about the Apollo [ph] 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 on what you've drilled to move forward more meaningfully if you did meet with success there?

Clarence Cazalot

Well, Arjun, it's a 2.5 million-acre play. If we're really good this year, we'll get one or two wells down. I think the answer to your question is, it's the former. We got a lot of work to do. Because each one of these blocks as you remember is close to 0.25 million acres. So even if you got one well, you'll have one well in 0.25 million acres which is the size of what you say some of our competitors have in these unconventional plays race in the United States. So a lot more work to do.

Operator

The next question comes from Blake Fernandez of Howard Weil.

Blake Fernandez - Howard Weil Incorporated

The first one is a little more detailed but it's on the corporate and unallocated income tax line item. It looks like it's up about $300 million year-over-year. I'm just trying to get a sense what that should look like going into next year?

Janet Clark

I think there's a lot that goes into that line in the press. And 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 widely different tax rates, anything from 25% to 93%. So as we get through the year and the next changes, our expectation of the full year effective tax rate also changes. What happened this year in the fourth quarter was that the mixed had changed to a lower tax jurisdiction and effectively we have been overbooking taxes the first nine months so we had to adjustment in the fourth quarter so that for the full year, we have 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 sold the biggest portion of that by converting our different tax liability in Canada to U.S. dollars. So we don't have that noise in the numbers anymore.

Blake Fernandez - Howard Weil Incorporated

So Janet, just to 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?

Janet Clark

No, I think that 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.

Blake Fernandez - Howard Weil Incorporated

And 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 would be in exported. And additionally, if you had any color on actually what percentage of your throughput is actually coming from Cushing or running WTI?

Gary Heminger

Right, as far as the percentage of exports of Apollo would be small. The key number that I spoke to earlier was about 40% takeaway capacity of Garyville. So if Garyville has, let's call it 460,000 barrels a day, and looked about 40%, it's not over just the new dock, it's overall the other docks we have as well. We have about 40% takeaway capacity on the docket then we take a tremendous amount of the pipelines both plantation and colonial pipeline. So what we're exporting is Europe, South America, Latin American and then we're also the largest supplier of bulk business into Florida. And the second?

Blake Fernandez - Howard Weil Incorporated

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

Gary Heminger

If I look at WTI reference crudes, about 20% is what I would call reference crudes, WTI. That's last quarter.

Operator

Our next question comes from Paul Sankey of Deutsche Bank.

Paul Sankey - Deutsche Bank AG

My question is actually an expansion of Arjun's first question regarding your competitive position as a standalone 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 is obviously shown a higher rate growth than integrated oil. And I wondered 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 want.

Clarence Cazalot

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 are not going to chase natural gas. We're in a fortunate position that where we have our gas resource for the most part, it has helped production. 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.

Paul Sankey - Deutsche Bank AG

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

Clarence Cazalot

Correct.

Paul Sankey - Deutsche Bank AG

And then briefly, Gary, you mentioned the theme of one Upstream, one Downstream. You mentioned on the Page 15 some of the quarter to date but actually didn't go there on the sweet/sour for you guys. Could you just talk a little bit about given that, that's what you said the most important thing, if you could just kind of give us the number, that would be great.

Clarence Cazalot

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've purchased to-date to give you the sweet/sour on an average basis today. Gary, do, you have sweet/sour for the month of January?

Garry Peiffer

From January?

Clarence Cazalot

You have sweet/sour weighted average for the month of January? I don't have it with me.

Garry Peiffer

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

Paul Sankey - Deutsche Bank AG

Do you know where it is right now?

Garry Peiffer

No, I don't. Not as of the moment. No.

Operator

The next question comes from Katherine Minyard of JPMorgan.

Katherine Minyard

First of all on the CapEx release, if I strip out the deal project from Downstream, it looks as though the Downstream maintenance CapEx levels is just a little bit lower than what you guys had previously guided towards a run rate. So just wondering if there's a certain lumpiness to downstream maintenance CapEx or how should we think about that going forward. The second question is, you guys gave a reserved book investment. I was just wondering if you also could give a rough F&D number with that?

Garry Peiffer

This is Garry Peiffer. The downstream CapEx, I think, you're referring to the fact that we set our kind of maintenance or sustaining capital is in the $700 million to $800 million range and obviously everything that's left over after we hope is a little bit less than that. But I think we've kind of trimmed back on some of those other sustaining if you will or maintenance type of things to accommodate the big spend on is 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. But we would still say, going forward, that our sustaining capital, maintenance capital is in that $700 million to $800 million range.

Clarence Cazalot

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

Operator

The next question comes from Mark Gilman of The Benchmark Company.

Mark Gilman - The Benchmark Company, LLC

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. Have, as a result of that, you reduced your expectations regarding decline rates? And what decline rate is implicit in the 2011 production guidance?

David Roberts

Mark, I think there is -- we continued to point towards the stability of the overall business to maintain 5% to 7% decline rate with investment. And I think if you break it down, the U.S. business is essentially going to be flat inclining this year and the forward business has a 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 clients that we have featured in this growth assets beyond conventionals have pretty aggressive upfront decline.

Mark Gilman - The Benchmark Company, LLC

You made reference to the seven discovers in Libya. Could you talk a little bit about what the production potential of those discoveries is and whether they are subject to EPSO terms or the more conventional and traditional tax concession arrangements?

David Roberts

Well we are not subject to EPSO 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 2D 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're 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 out and for businesses outside of that environment and generally still encouraged about the direction we're going in Libya.

Mark Gilman - The Benchmark Company, LLC

U.S. gas price, natural gas price realization in the quarter, seemed very much out of line with the pass and with the bid-week marker. Is there something in there we should be aware of?

Clarence Cazalot

Not that we're aware of, Mark. We're looking at as -- nothing to strike. Let us look at the fact and we'll get back to you.

Operator

The next question comes from Pavel Molchanov of Raymond James.

Pavel Molchanov - Raymond James & Associates

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?

Clarence Cazalot

Well, Pavel, is that question specifically for Droshky?

Pavel Molchanov - Raymond James & Associates

I suppose for the E&P business overall.

Clarence Cazalot

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

Pavel Molchanov - Raymond James & Associates

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

Clarence Cazalot

It's what I just mentioned. I think it will be between $14 and $17.

Pavel Molchanov - Raymond James & Associates

On the downstream side, actually kind of a hypothetical, if I may, if you have decided to do the spinoff, let's say six months or nine months earlier, would you have still sold Minnesota?

Gary Heminger

Yes, that has been our long-term strategy. The market in late '08, we were talking about this. I think there had been some hints of 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 have been working for this for 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.

Operator

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

Paul Cheng

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

Garry Peiffer

It would be less than 10%.

Paul Cheng

In terms of your crude slate on the sweet and sour defense. It's only 10% of your crude will benefit from the widening there? I thought it will be higher than that.

Garry Peiffer

Paul, the way we calculated in our basket, is that out there is only 15% of that basket is what your Canadian is left.

Paul Cheng

I was talking about that let's say in the first quarter you're seeing that -- we know that spread maybe up say based on what you saying to about $9.50, so it's up about in the $0.80. Should we assume your margin will have say a 50% benefit of that $0.80 or $0.60, or how much of that should we assume? So you have sweet and sour defense improved by $1 per barrel. Does that translate into $0.50 per barrel improvement in your realized margin or. . .

Garry Peiffer

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

Paul Cheng

After-tax?

Garry Peiffer

After-tax.

Paul Cheng

Annual?

Garry Peiffer

Annual.

Paul Cheng

And Garry, on the contango market, you said 55% to 60% of your crude purchase will be impacted by contango market or lesser?

Garry Peiffer

It's probably closer to about 75%.

Paul Cheng

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

Garry Peiffer

Yes, sir. Well that's what it was last quarter. There is obviously with the crude slates, but that's about the right number, about 75%.

Paul Cheng

And then for Dave, for the Woodford, you are saying that you expected exit rate to be a bit over 7,000 barrel per day. Do you have a longer-term target and also maybe three- or four-year time, what is your expectation for all your unconventional shale oil expectation?

David Roberts

Yes, Paul, we have not settled on a target for Woodford get a long term that we're willing to publish. But just generally, shorthand, we want all of these businesses to be about 25,000 barrels a day in minimum.

Paul Cheng

Each individual basin?

David Roberts

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 Niobrara, and we're still sticking with the 22,000 plus that we have in the Bakken.

Operator

[Operator Instructions] The next question comes from Doug Leggate of Bank of America Merrill Lynch.

Douglas Leggate - BofA Merrill Lynch

I wanted to try a question I guess I tried a couple of weeks ago, again, Dave Kurdistan, our understanding is that ShaMaran has reported some pretty good results that are in the well. And I wonder if you could give some colors 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 cost will be once all these one-off costs and so on are done, so we get an idea what the go-forward margin should be in that business?

David Roberts

I think we expect the cash operating cost on a go-forward basis to return what they were to were -- in the range, at 2009, at $35, $40 a barrel. After they popped up to $63 largely because of the turnaround, and we expect when we get the additional volumes on that we'll get back into those ranges and that certainly where we're targeting as a consortium. And I know Shell is 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 minister right now. We continue to be encouraged with what we're seeing on the drilling results, and we will get the results out just as soon as we can.

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

Howard Thill

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

Operator

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for participating. You may all disconnect.

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