馬拉松石油 (MRO) 2006 Q1 法說會逐字稿

Good day everyone, and welcome to the Marathon Oil Corporation first quarter 2006 earnings conference call. Today's call is being recorded.

For opening remarks, I would like to turn the call over to Mr. Ken Matheny, Vice President of Investor Relations and Public Affairs.

Thank you very much, Keith. Good afternoon to all. I too would like to welcome you to our first quarter 2006 webcast and teleconference call for Marathon Oil Corporation. Let me begin by reminding you that if you're listening via telephone, you can find the synchronized slides that accompany this call on our website, www.marathon.com.

With me on the call today are Clarence Cazalot, President and CEO, Janet Clark, Senior Vice President and Chief Financial Officer, Phil Behrman, Senior Vice President, Worldwide Exploration, Steve Hinchman, Senior Vice President Worldwide Production, Gary Heminger, our Executive Vice President and President of Refining Marketing and Transportation Organization, and Gary Peiffer, Senior Vice President of Finance and Commercial Services for our downstream organization.

Slide 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions today will contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially, from those expressed or implied by such statement.

In accordance with the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10K for the year ended December 31st 2005, and subsequent forms 8K 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.

You will note from our earnings release this morning, and in our comments today, that we have moved to an after tax segment reporting basis. This morning we posted our quarterly investor packet to our website. This packet was also sent to you if you were on our e-mail distribution list. And you will note there's a new page in the packet that provides by segment, pretax income, the provision for income taxes, and the net of these two items, or segment income.

I need to point out that all segment information provided for the second through the fourth quarters of 2005 and full year 2005, is preliminary and subject to revision. Because our effective tax rate has changed significantly, I want to take a few minutes to explain why it has changed. Annually we estimate our income tax provision and then calculate an effective tax rate for the year, by aggregating income taxes arising from all jurisdictions and countries where we operate.

For quarterly reporting, the income tax provision for the quarter is determined by applying this estimate of our annual effective tax rate to quarterly pretax earnings. Because the Libyan tax rate exceeds 90%, our overall estimated tax rate for 2006 is 47%. Because Libya is included in the E&P segment, the effective tax rate for that segment is approximately 50%. And the timing of liftings, especially in Libya, can have a significant impact on quarterly segment income, and can result in volatility of segment income quarter-over-quarter.

A good example of that is the current quarter where we were underlifted in Libya by nearly 2 million barrels, while the actual statutory rate in Libya exceeds 90%, the rate we are required by GAAP to utilize in determining that income, is the previously discussed 47%. Therefore, had these barrels been lifted in the first Quarter, we estimated it would have met approximately $60 million in additional net income, or approximately $0.16 per weighted average fully diluted share.

Therefore, when we eventually balance our lifting position, we will likely have a significant increase in net income. You will note that tax affects in the upstream are a significant variance in nearly call cases, when comparing this past quarter's performance against prior periods. Again, as our overall effective tax rate in the first and fourth quarters of 2005 were 38% and respectively, versus 47% in 2006.

As shown on slide 3, net income for the first quarter was $784 million versus $324 million in the first Quarter of 2005. Excluding the impact of the U.K. long-term gas contracts, net income adjusted for special items was $739 million, versus $357 million in the same quarter last year.

Now, turning to slide number 4, there was a substantial increase in net income adjusted for special items year-over-year. And it was driven by 4 major factors. Positive price, variance, and volume variance in the E&P segment. Overall improvement in Refining Marketing and Transportation businesses compared with the same period last year. And finally, holding 100% of the Refining Marketing and Transportation operations during the quarter just closed, versus 62% in the same quarter last year. Improved pretax income approximately $200 million, and net income by about $120 million. These positive factors were substantially offset by higher taxes as previously discussed.

Moving to slide number 5, the decline in adjusted net income from the fourth quarter 2005 was largely a result of reduced earnings in the RM&T segment, partially offset by lower taxes despite the higher effective tax rate. A reconciliation of net income adjusted for special items to net income is included on slide 3, refer to slide 2 for discussion of the use of this nonGAAP measure.

Moving to slide 6, first quarter per share net income adjusted for special items on a fully diluted basis was $2.01, a decline of 44% from the fourth quarter of 2005, and there were approximately 368 million diluted weighted average shares outstanding for the quarter.

Upstream segment income of $477 million for the quarter, as shown on slide number 7 was $265 million lower quarter over quarter. Our worldwide sales price was down $1.21 on a barrel of oil equivalent basis, while sales volumes averaged approximately 15,000 barrels of oil equivalent per day, less than last quarter due to the timing of liftings. However, actual available for sale volumes were up 46,000 barrels of oil equivalent per day primarily a result of a resumption of production from Libya.

Moving to slide number 8, domestic upstream income of $245 million, was $72 million lower than the fourth quarter. Domestic liquids realizations increased $0.52 per barrel while natural gas decreased $1.64 per MCF. Sales volumes were lower by approximately 4,000 barrels of oil equivalent per day, largely as a result of the [Kanman] Hills field watering out in the first quarter 2006, which was earlier than expected. As shown on slide 9, lower gas realizations and lower volumes were partially offset by lower exploration expense.

Total expenses in the domestic upstream segment that is shown on slide 10, were up $0.13 per barrel of oil equivalent, compared to the fourth quarter. Expenses excluding exploration expense were $19.65 per barrel of oil equivalent, compared to $17.73 per barrel of oil equivalent in the fourth quarter of 2005. $1.92 per barrel of oil equivalent increase in expenses is a result of an impairment of $20 million, associated with a watering out of Kanman Hills, in the Gulf of Mexico, and higher than anticipated employee bonuses paid in the first quarter. Adjusting for these two nonrecurring costs that total of $1.78, total expenses excluding exploration were flat with the fourth quarter of 2005.

Moving to slide number 11, domestic upstream income per barrel of oil equivalent decreased $3.68 quarter-over-quarter, largely the result of lower natural gas realizations, and the previously discussed increase in nonrecurring expenses.

Moving to the international upstream on slide number 12, international income of $232 million was down approximately 45% from the fourth Quarter, mainly due to lower liquid sales volumes and higher taxes, primarily associated with the resumption of production in Libya. The lower liquid sales volumes were the result of a substantial makeup in sales volumes during the fourth Quarter of 2005 for underliftings during prior periods, followed by the underlift in the first quarter of 2006, primarily in Libya, [Point Alvheim], and Equatorial Guinea.

Slide 13 shows the impact of higher taxes on our International income, again due to our resumption of production in Libya. Moving to slide number 14, total international upstream sales volumes decreased approximately 5% compared to the fourth quarter. This is due to the timing of crude oil liftings.

International first quarter production available for sale increased by 50,000 barrels of oil equivalent per day when compared to the fourth quarter. International upstream expenses increased approximately $1 per barrel of oil equivalent compared to the fourth quarter, as a result of higher exploration expenses. Excluding exploration expense, international expenses were relatively flat with the fourth Quarter.

Slide number 15 shows that international upstream income for decreased almost $9 per barrel of oil equivalent. Largely a result of the higher average tax rate used across all pretax income and our underlift position.

Moving to our downstream business in slide number 16, first quarter segment income of $319 million was significantly higher than the first Quarter 2005 segment income, with approximately $120 million of this segment's first quarter 2006 income, coming as a result of June 30 2005 acquisition of the 38% minority interest.

Because of the seasonality in the downstream business, I will compare the first quarter 2006 results against the same quarter in 2005. Other significant contributing factors to the downstream improvement were, first the increase in crack spreads. Second, in the current quarter derivative activity related to our crack spreads and trading derivative strategies, netted to a nominal amount, while the same quarter last year had a negative $104 million pretax income related to these strategies.

Third, we processed about 5% more total inputs, and finally, we realized a higher price on our volume metric gains last quarter, compared to the same quarter last year. In addition, we had a negative pretax crude in transit effect of about $20 million in the first quarter of 2006, compared to a negative $73 million in the same quarter last year. Thus improving last quarter's results by $53 million pretax and pre-minority interest compared to the same quarter last year. Since we have elected not to use hedge accounting for our Refining Marketing & Transportation derivative activities. All of our derivative activities are required to be mark to market through income. Marking to market all of our other RM&T derivatives resulted in a positive impact this quarter versus the same quarter last year.

Finally, crude oil markets were in [Cantango] about $1 per barrel on average during the March 2006 quarter versus being only about $0.33 in the same quarter last year, which improved our domestic crude oil acquisition cost compared to the 2005 quarter. These positive factors were partially offset by higher costs we incurred last quarter compared to the same quarter last year, primarily due to higher purchased energy costs, refinery maintenance and turnaround expense, as well as higher depreciation recorded, primarily resulting from our purchase of the minority interest last year. Our cost of sales was higher last quarter than the change in WTI quarter-to-quarter, would suggest. Primarily because we ran less sour crudes last quarter than during the March 2005 quarter.

This reduction was primarily due to maintenance we performed in our Garyville refinery last quarter. In addition, we had some negative inventory affects last quarter, due to the timing of bills and draws of inventories quarter-to-quarter.

And finally WTI gasoline and distillate spot prices increased significantly last quarter, as did our wholesale realizations for these refined products. However, our other refined product realizations lagged the increase in spot prices of gasoline and distillates. Resulting in a lower realization in total, and a change in spot market prices included in the WTI 6321 calculation would indicate.

Shown on slide number 17, Speedway SuperAmerica's gasoline and distillate sales were up 31million gallons quarter-over-quarter, or about 4%. Speedway SuperAmerica's same store gasoline sales volumes were up 3.3%, even though Speedway SuperAmerica's retail gasoline prices averaged about $2.27 per gallon last quarter, compared to $1.89 per gallon in the same quarter last year.

Speedway SuperAmerica's merchandise sales on a same store basis increased a little over 10% last quarter from the same quarter in 2005. And this marked the 13th consecutive quarter that Speedway SuperAmerica's merchandise sales have increased over 9% on a same store basis. Speedway SuperAmerica's gross margin for gasoline and distillate was $0.106 per gallon, which was roughly equal to the gross margin per gallon realized for the same period last year.

We had an increased amount of maintenance at our refineries during the first quarter, which reduced our total refined crude oil from 922,000 barrels a day in the first quarter of 2005, to 898,000 barrels per day last quarter. However, we offset some of this reduction in crude oil throughputs by increasing other feedstock through puts, which totalled 249,000 barrels per day, compared to 171,000 barrels day in the same quarter last year. Based on all of the work we have done to date and our current work schedules, we expect to have all of our ultra low sulfur diesel projects complete and operational by June 1st, 2006.

Turning to slide number 18, the Integrated Gas segment income was $8 million during the first quarter 2006, compared to a loss of $2 million in the fourth quarter 2005. In the Corporate and Other unallocated expense category, which includes unallocated administrative expenses, as well as net interest and financing costs, after tax costs were $65 million in the first quarter. The $21 million decrease in the fourth Quarter was primarily a result of higher capitalized interest. And as previously discussed, the effective tax rate was 47% reflecting the impact of our resumption of activity in Libya. Cash adjusted debt went up by $1 billion during the first quarter to $2.4 billion, and the cash adjusted debt to capital ratio at March 31st, 2006, was approximately 17%.

I will note that the cash adjusted debt balance continues to include about $540 million of debt serviced by U.S. Steel, and that these are preliminary numbers. First quarter preliminary cash flow from operations was approximately $250 million, and preliminary cash flow from operations before working capital changes was approximately $1.2 billion.

Slide 19 provides information from prior periods, as well as estimates for the second quarter and full year 2006. Again, please note the tax rate going forward is expected to be in the range of 46 to 48%. Also remember that we plan to ratably repurchase a total of $2 billion in shares during 2006 and 2007.

Assuming an $80 share price, this would be just over 3 million shares during the second quarter, and would reduce our weighted average fully diluted shares outstanding for the second quarter to approximately 367 million shares.

I would also like to ask you all to mark your calendar for our Analyst Day which we will hold in New York on November 29th. And we will be sending out a hold the date notice in the near future.

We're now ready to take questions. In the interest of fairness to all of those wishing to ask a question, I ask that you please limit yourself to one question and a related follow-up. You may then reprompt if you have additional questions.

Keith, you can go ahead and open up the lines.

Thank you, ladies and gentlemen, the question and answer session will be conducted electronically. [OPERATOR INSTRUCTIONS] We'll go first to Nikki Decker, Bear, Stearns. Please go ahead.

Good afternoon. I think I'll start off with a question on the Bakken Shale, could you describe the prospectivity of those reserves per well? The cost that you anticipate per well and the capital program that you anticipate committing to this?

Yes, Nikki, this is Steve Hinchman. We've acquired in a series of land acquisitions around 200,000 acres. The Bakken Shale currently has drilling units of 1280. So assuming the 200,000 acres, we have around 150 drilling units. If you assume that there's two wells per drilling unit, where we think there's the potential to get as many as 4. There would 300 to 600 well locations associated with the 200,000 acres.

The statistical average in the Bakken to date would have the estimated ultimate recovery per well somewhere around 330.000 to 360,000 barrels of oil. So again, roughly if you take even two wells per 1200 acre 80-acre drilling units, that would translate to 300 wells, with a recovery of over 300,000 barrels per well. Or something roughly on the order of 100 million barrels of reserve potential.

We estimate that the well, a well would cost somewhere between 3.5 and $4 million. That's drill and completed. We'll be ramping up our activity, we'll be moving a rig into Bakken in May. We'll add a second rig in June, and be up to around 3 rigs running by the end of the year. But ultimately we would expect to ramp up to around 8 rigs by 2007. And that would translate into a drilling program out through around 2012 to drill, you know, roughly 300 wells. So the capital program, of course, can be flexible depending upon ultimately how many wells you choose to drill, but that, that would basically be our plan.

Thank you. And are the bulk of those acres in Montana or North Dakota?

We have, of the 200,000, we have roughly 15,000 in Montana, and the rest of it is in North Dakota.

Great. Thank you.

We'll go next to Steve Enger, Petrie Parkman. Please, go ahead.

Hi, guys. On downstream, as we looked at your refining margin, you know, basically from the indicators, we would have projected higher refining results, and Ken provided some comments on some of the things that went on, but I guess I'm still not sure I'm clear. Can you provide some additional comments on some of the more important things that would have in the end reduced that realized refining margin relative to the indicators?

Yes, Steve, this is Gary Heminger. First of all, probably the biggest thing from a throughput standpoint would be some, some turnaround activity, unplanned downtown at Garyville. Which took about 7.5 million barrels out and not every barrel is created equal as you understand. Garyville is usually our most profitable refinery. So on average, let's say 7.5 million barrels out, that was probably in the in the vicinity of 35 to $40 million of income there.

Okay.

In addition, as Ken stated. The other big pieces with the turnaround expenses of $40 million, and about $50 million of increased energy costs, those were two other big expense items, and part of that turnaround expense was for a little bit of turnaround that we have brought forward, that was going to be completed in the second quarter, we were able to go and get that done while we were down at Garyville. So those would be the big issues.

Thanks for that clarification. And my very closely related follow-up. Gary, if, as we're getting very close now to a number of changes in specs and regulations in the downstream, particularly ethanol for MTBE coming, can you give us an update as to how you see, you know, the change in winter to summer blend gasolines, followed, you know, very closely on the heels with ethanol, and then not too far down the road, the ultra low sulfur diesel. I know you guys are good to go, but what are you seeing out there in the marketplace?

Well, if you look at kind of the overall industry indicators, and we don't have March data yet, but in February, there was 302,000 barrels a day of ethanol produced versus same period last year of about 245,000 barrels per day. So what you're seeing is that Ethanol had been pre-positioned getting ready for the lower vapor pressure material that comes into the terminals here in early May. Which has really put a strain on the logistics assets being mainly railcars and trucks that are moving this product to the marketplace.

And it's not necessarily the strain inside the Midwest, it's moving it to the two coasts, is really where the strain is, and moving that Ethanol much further distances than we have seen in the past. You know just recently, ethanol has come off about $0.20 to $0.25 a gallon.

Again, would suggest that from an overall inventory standpoint they're getting in better shape, but I would say it's really logistics that are continuing to put a pinch on some of the coast.

Great. Thank you.

We'll go next to Neil McMahon, Bernstein. Please go ahead.

Hi, I think in the past you would have summarized your interest in the oil sense in Canada, was very much linked into your refining position and PAD2, and what you could do in terms of upgrading the refineries to accept the crude.

Have you changed the model at all there in terms of your feelings towards owning oil sands from the upstream point of view, and integrating that way? I was wondering what your latest comments are on that.

No, I think, this is Clarence, I'm sorry, I think in the past what we've discussed is we see the value proposition being that of an integrated transaction. And I think we continue to view it that way. It's not without its hurdles.

I think as we've also described the biggest issue is the relative valuation of assets between the Canadian oil sands in the upstream, and the downstream value proposition is brought to the table. You know, nothing has changed in terms of our view that an integrated transaction makes sense, and I think we continue to pursue it on that basis.

Maybe just as a follow-up to that, certainly, I know this was getting discussed maybe as long ago as a year and a half. What are the key things that have changed over time in terms of the, say the economics or just the logistics of some sort of deal coming together. I know you were trying to get a good handle on the sort of spread, the ceiling, and floor to any spreads, and trying to work that out with a producer. What's changed, why is such an integrated deal being held up?

Well, Neil, this is Gary, I would say what has changed is the overall market. If you go back and look at the, the values placed on oil sands assets and equities surrounding oil sands last year, changed significantly. You have that side of the table still understanding what is the best way to produce, whether you go to a Dilbit, and in fact, that has changed in the last year from a Synbit type of an end product to more of a Dilbit, because upgrading economics, the cost to upgrade has risen exponentially.

Secondly, there are many key variables that did not move in a linear fashion. You have natural gas, in order to be able to provide the steam to these wells. If you look at a Seg-D type of a process, you have a diluent strategy, be it a condensate that has to be moved into the marketplace to be able to blend with the Bitumen, and move that product away.

You have the cost of upgrading then at the refinery location. And also, you have another big component that has not been finalized yet, and that is the transportation solution from the Edmonton Fort McMurray, I should say Athabasca area, down into PAD2, and that is not something just to pass by, you really have to understand that solution before you can move.

So many complex dynamic moving variables that you have to get your arms around, and it's not just on the upstream or downstream side. You have those variables going in both directions, so it's taking more time, as well. We agree with you, it is taking more time than we had hoped for, but believe me, we have a large team, and everybody's working hard to see if there can be a solution.

And Neil, this is Clarence, I would only say that recognizing the complexities that Gary just talked about, and the fact that we have begun talking about this opportunity probably 18 months ago, it really wasn't until the second half of last year, post finalization of the acquisition of the minority interest, that we could actually pursue it on a serious basis, fully engaging our downstream business. So frankly, we've really not even been at this seriously 12 months yet.

Okay, great, thanks.

We'll go next to Mark Flannery, Credit Suisse.

Hi. This is a question on the cost of refinery expansions and upgrades. I know you're probably in the middle of or some way through the front end engineering design for your proposed Garyville expansion. I wondered if you could share with us whether you're seeing any significant cost increases there, in the estimated unit cost, or whatever of adding new capacity, and/or upgrading existing capacity.

Sure, Mark. Gary again. I will, I must put a caveat that we're only about 15% through on the FEED process of the engineering design of Garyville. So, you know, we're just out with some of the big vessels and some pieces of equipment that we're getting some bids to understand the price. Like others in the industry that have remarked this quarter, and specifically the last few days here as earnings have been released.

We too are seeing an increase in labor costs, per diem costs, fabrication shop space available, that obviously will push those costs up. However the number that we put out, we said initially an approximate $2.2 billion capital cost in Garyville. Yes, we're seeing that number go up, we're not seeing it go up too material at this point.

Great. Okay. Thank you very much.

We'll go next to Jennifer Rowland with JP Morgan.

Thanks, I have a question on your production guidance for the second quarter. What's causing the drop in domestic natural gas forecast there?

Jennifer, this is Steve. Most all of that is associated with seasonal gas sales in Alaska.

Okay. And my second question is, I think you are still drilling the, I think it's the [Davon] prospect in the North Sea, I was just wondering if that's been completed, and if you could comment on any other exploration wells that you have drilling currently?

This is Phil Behrman. No, the Davon well reached TD, that's a dry hole, it's got [no economic] hydrocarbons in it. We're currently drilling a well in block 31 of Angola, and we're also drilling the Abbott well, it's a deep shelf well in the Gulf of Mexico.

Okay. Okay. Thank you.

We'll go next to John Herrlin, Merrill Lynch.

Yes, hi, just a quick one on the Bakken. Does most of your acreage have the [middle delvolite] member, do you know?

Yes, pretty much. You know, without disclosing how we target it, we believe that our acreage is, prospective relative to what we do as successful attributes in the Bakken.

Right. Will you be doing duals? Dual horizontals?

Yes, we'll do duals and we're thinking about even attempting some very extended reach, pushing a single lateral as far as 10,000, but we have a learning curve to go through first. We're going to go in and learn from what others have done, and potentially build to that.

Thank you.

We'll go next to Doug Leggate, Citigroup.

Good afternoon, folks. My question is on your LNG business. Clearly your maybe just over a year away now from first gas coming out of EG. Our understanding is that you've, the situation regarding your ability to talk about the terms of the contract with EG have been I guess relaxed a little bit, in terms of maybe giving updated guidance.

Could you give us an idea, or are you yet in a position to give us an idea of what your earnings could look like out of there, under let's say a more realistic gas price than what you did back in 2003? And secondly, could you update on the, my belief that Nigeria is apparently now in discussions with the potential for supplying gas into the second train.

Hey, Doug, this is Clarence, Two things, I would just reiterate, First cargos for LNG Train 1 out of EG are third quarter of 2007, not a year from now.

But with respect to BG, no we have not gotten any additional agreement from BG, with respect to our ability to disclose the terms of our off-take agreement with them so that, you know, at this point we're really not in the position to give you any better guidance on what our earnings would be at any particular gas price. We've not given up on that yet.

Certainly the time is growing closer to where those actuals will be reflected in our financials, so obviously that is something we continue to stress, and we'll continue to pursue that. I think we have said several times before that indeed both Nigeria and Cameroon are being looked at as potential sources of gas for a second train.

Indeed, there have been MOUs signed between EG and Nigeria, and between EG and Cameroon, signalling good government to government cooperation there. That is continuing. So I think there is a recognition by both of those countries that the vision we have of a regional gas hub at Bioko Island makes a great deal of sense for them, as well as it does for EG.

How are you feeling about the potential FEED situation, is that something you would pursue in the second quarter, or are we any getting closer to it?

We're getting closer to it, and I would say stay tuned.

All right. Thanks.

Ladies and gentlemen, [OPERATOR INSTRUCTIONS] We'll go next to Mark Gilman, Benchmark. Please go ahead.

Guys, good afternoon. On the Bakken, can you give me an idea of what the land acquisition costs were, and what kind of recovery rates per well, Steve, you're expecting?

Mark, I can't divulge specifics, I can merely tell you that we're, we average, our average land acquisition cost is, you know pretty close or approximate to what a lot of the state lease sales have been going for over the last 3-4 months. Regarding the per well, as I mentioned earlier, we'd estimate that per well EUR is about 300,000 barrels per well, as well.

And that would represent an in-place recovery rate of what?

About. I'm not sure I know that number off the top of my head. 7%, 10%, you know depends on what you assume is a contributing thickness in the shale, Mark. But what we're looking at, is the number I'm quoting you is really the statistical average on all of the wells that have been drilled in the Bakken to date, and I think that's really the best source for estimating recovery at this time.

Okay, and I have one totally admittedly unrelated follow-up. With respect potential to the [Goodrun] development, the way you see it under whatever scenario you might be evaluating it, would it require the use of any of your Norwegian tax loss carry forwards, in order to make that go, or do you expect that the bulk of that will be chewed up on Alvheim?

Mark, this is Phil, all of the Norwegian NOLs will be used up early on in the Alvheim development, even the follow-on Volan tying into Alvheim, there won't be any losses, loss carry forwards to be used on that project. So obviously Goodrun won't benefit from any of those losses, either.

So it would have to stand on its own, Phil?

That's correct.

Very good, thanks very much.

We'll go next to Paul Sankey, Deutsche Bank.

Hi. Good afternoon, gentlemen. First one was on your refinery throughputs about 1.14 million, 1.15 million barrels a day, will we expect to see a bounce back in those volumes beyond the 1.24 million you saw in Q4? I'm aware that you had Garyville down during the quarter, I presume this is a low number for the year.

Right, Paul. We feel very good that we're going to bounce right back, in fact, things are running very well. And it wasn't just Garyville, we completed some other turnaround activity in the first Quarter, and I would expect things to bounce back in line with our past history.

Okay. So you don't expect to go higher on a sustained basis?

Oh, I'm sorry, I was saying that I didn't expect that, that you know, we were going to have problems or lower runs. We would expect, you know, if you look at history, then you also need to look at our expansion to Garyville that would not, you know, we really didn't have a full quarter last year, with Detroit's expansion, so you could see some bounce barring any unplanned down time, a bounce in some of the throughput.

Okay. Could you talk a little bit more about the way your throughput is changing. You've got crude down and overall throughputs up, is that a continued dynamic? And is that to do with what you were saying about Canadian heavy oils?

No, the dynamic there is we have the ability through our, you know, offstanding logistical system to quickly access sour gas oils, or sweet gas oils when we're down, to be able to fill the cat crackers, so that's really what you're seeing going on.

And is that going to be the kind of rate that you see if you like, the proportion you'll see going forward in terms of crude and other?

We will optimize based on the values of the crude. It's all going to be based on, you know, the heavier crude discounts, and the yields off of those crudes, versus the yields off the cat crackers running a sour gas oil type of feedstock. So it will all depend on differentials, and the relation between those differentials.

Thank you very much, Paul. We're going to have to go on to the next question.

Our next question is a follow-up with Mark Gilman, Benchmark Co.

Hey, Gary, would it be appropriate or not to look at the expansion in Garyville, and the Canadian you had the integrated joint venture, as an either/or proposition?

Well, yes, we're looking at, you know, they both have very long lead times. And they're two different strategies that we have continuing to increase, you know, very value-oriented increase in value type projects within Marathon Oil. Garyville is one of those, a long-term integrated strategy on the Canadian oil side is another one of those long-term strategies. So you could look at them independently, obviously we'd recommend looking at those independently, or you could look at those as going along kind of on the same path.

You want to try another shot at answering the question?

We could potentially do both.

Thank you, Janet.

And at this time, we have no further questions. I would like to turn the conference back to your speakers' any additional or closing remarks.

Thank you, Keith, we don't really have any closing remarks, other than to thank everybody for their participation. Good-bye.

Ladies and gentlemen, this does conclude today's teleconference, we appreciate your participation, you may disconnect your phone lines at this time.