馬拉松石油 (MRO) 2010 Q1 法說會逐字稿

Good day, welcome to Marathon Oil's 2010 first quarter earnings conference call. As a reminder, this call is being recorded.

For opening remarks and introductions, I would like to turn the call over to Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thanks, Operator, and I've certainly been called worse.

I would also like to welcome everyone to Marathon Oil Corporation first quarter 2010 earnings webcast and teleconference. The synchronized slides that accompany this call can be found on our website at marathon.com.

On the call today are Janet Clark, Executive Vice-President and CFO; Gary Heminger, Executive Vice-President Downstream; Dave Roberts, Executive Vice-President Upstream; and Gary Piper, Senior Vice President Finance and Commercial Services Downstream.

Slide two contains a discussion of forward-looking statements and other information included in this presentation. Our remarks and answers to questions today will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-K for the year ended December 31, 2009, and subsequent forms 8-K, cautionary language identifying important factors ,but not necessarily all factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note that in the appendix of this presentation is a reconciliation of quarterly net income to adjusted net income for 2009 and the first quarter of 2010. Preliminary balance sheet information, second quarter and full-year 2010 operating estimates and other data you may find useful.

Slide three shows the 38% increase in adjusted net income compared to the fourth quarter 2009, and 31% increase from the first quarter 2009, as well as details by quarter since 2007.

Slide four shows the components of the 38% increase in adjusted net income compared to the fourth quarter 2009. The increase from the fourth quarter was largely driven by higher commodity prices and lower income taxes, partially offset by lower refining and wholesale marketing gross margin, and lower ENP production sold.

Pretax earnings decreased in the RM&T, Oil Sands Mining and EMP segments. The income taxes decreased as a result of the lower pretax earnings and the adjustment for foreign currency remeasurement of deferred tax. The fourth quarter included a $139 million loss on the remeasurement of deferred taxes, denominated in foreign currency, while the just completed quarter saw a $33 million gain, netting to the $172 million FX swing shown on the waterfall chart.

As explained on the February conference call, because we will make a one-time election to begin paying Canadian income tax in US dollars, which is the largest portion of these fluctuations, the amount of FX on these Canadian balances was significantly reduced in the first quarter and will be eliminated after the second quarter. However, we will continue to have the potential for movements related to deferred tax balances other than Canadian, but -- sorry, other than Canada, but FX fluctuations should be significantly less than those experienced in the past because our deferred tax liabilities denominated in foreign currencies will be much smaller.

Slide five shows the 14% increase in ENP segment income to from $439 million in the fourth quarter to $502 million in the first quarter. The largest impacts were the increase in liquid hydro carbon and natural gas prices and lower income taxes, largely offset by reduced sales volumes as a result of an underlift in the UK, turnaround activity in Equatorial Guinea, and our normal 6% to 8% per annum production decline rate.

Slide six shows our historical realizations and the $3.97 per BOE increase in our average realizations from $49.93 per BOE in the fourth quarter to $53.90 per BOE in the first quarter. Our liquid hydrocarbon realizations increased more than the NYMEX prompt WTI price as about 60% of our global liquid hydrocarbon sales are based off of Brent, which outperformed WTI during the quarter. Neither our ENP nor our oil sands mining realizations include the gains and losses on our hedging positions. Included in the ENP results were $51 million of net pretax gain on these ENP hedges related to 65,000 bpd of crude oil hedges, which all roll off at the end of June, and 110 billion Btu per day, or approximately 110 million cubic feet per day, of natural gas hedges that run through the end of 2010. Complete details of our hedging positions are included in our 10-K.

Slide seven shows the production volume sold in the first quarter of 2010 were down 13% compared to the fourth quarter of 2009, to 361,000 BOE per day, while production available for sale decreased 10% to 364,000 BOE per day, while production available for sale decreased 10% to 364,000 BOE per day, primarily driven by the planned turnaround in Equatorial Guinea. The difference in sales volumes and production available for sale as the result of an underlift for the quarter of approximately 220,000 BOE, again primarily in the UK.

Turning to slide eight. While field level controllable costs were slightly lower from the fourth quarter and expiration expense was down, total expenses per BOE, as shown on slide nine, increased 6.5% from the fourth quarter, primarily driven by higher DD&A per BOE as a result of volume mix. First quarter ENP segment income was $15.42 per BOE, a 34% increase compared to the fourth quarter of 2009, again primarily due to the higher commodity price realizations, and lower expiration expense partially offset by higher DD&A per BOE and other costs.

Turning to slide ten, in Oil Sands Mining, the segment loss for the fourth quarter was $17 million, declining $58 million from the $41 million earned in the fourth quarter 2009, largely driven by lower sales volumes as a result of the planned turnaround activity. Operating and blend stock costs increased $17 million, reflecting $30 million of turnaround costs incurred in the first quarter, and a decrease in other operating and blend stock costs as a result of the lower volumes.

Marathon's first quarter 2010 net synthetic crude production, bitumen after upgrading and excluding blend stocks, from the AOSP mining operation was 21,000 barrels a day, compared to 26,000 barrels per day in the fourth quarter. Average realizations, which, again, do not reflect the gain or loss on hedges, increased $5.27 per barrel from their fourth quarter level. First quarter segment income reflected a $10 million pretax loss on derivative activity, which reflects 25,000 Bpd of crude oil hedges at $82.56 and that run through the end of this year.

Turning to slide 11, and the Integrated Gas segment, first quarter segment income was $44 million, up $7 million from the $37 million earned in the fourth quarter of 2009. The quarter-over-quarter increase was primarily attributable to reduced expenses related to the development of natural gas commercialization technologies and higher LNG and methanol price realizations, partially offset by lower LNG sales volumes as a result of the turnaround in Equatorial Guinea. As noted on slide 12, RM&T's first quarter 2010 segment loss totaled $237 million, compared to $159 million segment income earned in the same quarter last year.

Because of the seasonality of the downstream business, I will compare our first quarter 2010 results against the same quarter in 2009. The majority of the quarter to quarter decrease was due to the fact that our crude oil and other feedstock costs were incrementally higher than the change in the average price of our benchmark LLS crude during the first quarter of 2010 compared to the same quarter last year. The primary reasons for the higher costs were lower sweet/sour differentials, and a weaker Contango market structure.

Also, manufacturing and other expenses were higher in the first quarter 2010 compared to the first quarter 2009, primarily due to relatively large planned turnaround and maintenance activities at our Garyville, Louisiana, and Texas City, Texas, refineries. Higher depreciation and purchased energy expenses were also factors in the higher manufacturing costs. In addition, our average wholesale price realizations increased less than the increase in the average spot market refined product prices used in the LLS 6321 crack spread calculation in the first quarter 2010 versus the same quarter in 2009. Partially offsetting these negative effects were increased returns from methanol blending activities due to wider spreads between gasoline and ethanol prices and the fact that we blended about 15% more ethanol during the first quarter of 2010 compared to the first quarter of 2009.

Total refinery crude oil throughput averaged 1,003,000 barrels per day in the first quarter 2010 compared to 851,000 barrels per day in the same quarter last year. Total throughputs were 1,100,000 barrels per day in the first quarter of 2010 as compared to 1,071,000 barrels per day in the first quarter 2009. Speedway SuperAmerica's refined product and merchandise gross margin was about $11 million higher in the first quarter 2010 compared to the first quarter 2009. The increase was primarily due to higher gasoline and distillate margin, which increased from $0.1068 per gallon in the first quarter 2009, to $0.1195 per gallon in the first quarter 2009. SSA's same-store merchandise sales increased approximately 7%, while same-store gasoline volumes were virtually unchanged quarter-to-quarter.

Slide 13 provides historical performance indicators for the downstream business and previously discussed LLS 6321 crack spreads.

Slide 14 provides an analysis of preliminary cash flows for the first quarter of 2010. Operating cash flow before changes in our working capital was $829 million. Our cash balance was increased by working capital changes of $20 million. Capital expenditures during the quarter were $1.3 billion. Disposable assets were also $1.3 billion, and dividends paid totaled $172 million.

Slide 15 provides a summary of select financial data. At the end of the first quarter of 2010, our cash adjusted debt-to-total-capital ratio was 21%, a reduction of 2 percentage points from the fourth quarter 2009. The effective tax rate for the first quarter of 2010 was 53%, in line with the expected effective tax rate for the full year of 2010 between 49% and 54%.

As we announced in the earnings release this morning, we will no longer issue an interim of date. Please remember that on an monthly basis we update the last page of our Investor Relations packet which provides the average NYMEX prompt WTI oil price and the 6321 crack spreads for the Gulf Coast and Chicago markets.

Clarence could not be with us on the call today, as he is in North Dakota visiting our operations and participating in the Williston Basin conference, but he wanted me to say that the collective thoughts of the Marathon family go out to those killed and injured on the Deepwater Horizon and the loved ones left behind.

We, like most Americans, are focused on the continuing efforts by the private and government sector to control and contain the spill in the Gulf. These are difficult and challenging times for us all. reflection on our own businesses to ensure we main vigilant and prepared for the unexpected. We have not experienced any significant operational impact from this tragic event, and at this time do not expect we will, but we will follow the unfolding of events closely and take the necessary measures should circumstances change.

I now turn the call over to Dave and Gary for comments around their respective businesses. Dave?

Thanks, Howard.

As noted in our release, and in Howard's remarks, the upstream performed within expectations for the quarter. We continue to improve on our safety performance in 2010, led by a top quartile performance in Equatorial Guinea during a one-month planned maintenance event that occurred in March. We completed all activities scheduled at all three businesses in EG ahead of schedule and within our cost projections. Production was returned to full rates on April 10.

All of our other conventional business had solid reliability in the quarter, continuing a trend of good performance in this area. Oil Sands Mining met our ranges, but continues to struggle to meet our reliability expectations. The AOSP project began a major turnaround in late March, with production expected to resume during the month of May. For the remainder of the year, we have additional maintenance planned at Alpine in August with an expected duration of 14 days, at (inaudible), also in August, with an expected duration of 30 days, and at the AMCO facility in EG in October with an expected duration of 35 days. This events have been considered on our guidance for the relevant quarters and for the year, and we are exploring methods to mitigate their durations.

In term of new production that will allow us to meet the expectations of the total expected upstream production of 412,000 to 438,000 barrels of oil equivalent per day in 2010, I'm pleased to report that Bolen began regular production at 13,500 gross barrels of oil equivalents per day in April, and we would expect that to increase to a rate of 25,000 gross barrels of oil equivalent per day in July. The Alpine complex continues to produce above the rated FPSO capacity at approximately 138,000 barrels of oil equivalent per day.

All subsea work at Drosky was completed in the first quarter and attention has turned to surface fertility completion at Bullwinkle. We expect production in the June to July timeframe with Drosky ramping up to 50,000 barrels of oil equivalent per day rate in the later stages of this year. Our current projections are that Drosky will be brought on stream for roughly $400 million below the sanctioned projections of $1.3 billion. We expect it's initial phase of activity will access approximately 50% of the 60 million barrels oil equivalent of net resource available with field performance dictating any additional activities required to fully capture the resource potential of the field.

On the exploration front, drilling continues at Flying Dutchman and Haynesbrook, two of planned Miocene target wells in the Gulf, with Bronco, our third operated prospect, expected to spud in later 2010, dependant on the delivery of the Noble Jim Day rig in the third quarter. The rig's first assignment after acceptance will be to complete the single well of (inaudible) project. The Dutchman has proven to be a challenging well to drill, but remains within our timing and cost projections. Haynesbrook has executed to this point with no difficulty.

Outside operators will continue to appraise the Freedom discovery in 2010, completing the picture for exploration in the Gulf of Mexico. A planned fourth exploration well by an outside operator has been deferred into 2011. In Indonesia, and on the Pasangayu Block, the Bravo well will spud in July, followed by the Romeo well in the October timeframe. The rig is in transit to the country and will complete it's initial well for another operator prior to to moving to our site offshore Sulawesi.

Finally, in the Bakken, we continue to grow our acreage and our production outlook. We now have 350,000 highly consolidated acres and our net production is close to 12,000 net barrels of oil equivalent per day. We are now projecting a peak of 22,000 net barrels of oil equivalent per day in 2013. As we've mentioned previously we'll be running six rigs in the basin by the end of the year, up from our current four.

We continue to evaluate the play in our technology, and are confident in the play and our ability to execute grows daily. In short, the business is performing very well, and we're pleased with our activity slate for the remainder of the year and into the future.

I'll now turn the call over to Gary Heminger. Gary?

Thanks, Dave.

The first quarter of 2010 was a challenging quarter for us financially, but very successful from an operational standpoint. We were able to complete the integration of all of our Garyville major expansion operations with the existing Garyville refinery, and I am pleased to report that all of the GME units are operating as expected at this time. In addition, as a result of the completion of the GME, we have started to sell some of our increased Garyville light products production internationally.

While this integration of the GME units was underway during the first quarter, we also completed a significant planned maintenance program at the base Garyville refinery. The centerpiece of this planned maintenance involved 125,000 barrels per day crude catalytic cracking unit, which recently completed a record seven-year run between turnarounds. While we had the FCCU down for maintenance, we also took this opportunity to to some additional maintenance work on this unit to prove it's overall reliability. In addition to the Garyville maintenance activities, we also completed a planned entire plant turnaround at our Texas City refinery during the quarter. And finally, we also started a major maintenance program at our Catlettsburg refinery in March, which was completed in April, as planned.

In total, we performed all of these major maintenance activities under budget in the in first quarter, and at the current time, all of these refineries are operating as expected.

Turning now to more current events on the supply some demand front, we have seen improvement in distillate sales throughout our marketing area in March and April. While the increase has been modest, we believe the drop in demand for distillate has bottomed and expect gradual improvement in demand the rest of 2010. Speedway SuperAmerica also has experienced increased same-store gasoline sales of approximately 1% in April.

Thank you and I'll now turn it back to Howard.

Thanks, Gary and Dave.

Before we open up to questions, I would like to remind you that to accommodate all who wish to ask questions, we ask that you limit yourself to one question plus a follow-up. You may reprompt for additional questions as time permits. And with tha, Operator, we will open the call up to questions.

Thank you, Mr. Thill.

(Operator Instructions).

And we'll take our first question of the day from Doug Terreson with ISI.

Good morning, everybody.

Hey, Doug.

I have a question for Gary about refining and marketing. Actually, I have a couple, but they're similar. So the first question is, a) how much of the feed talk for Garyville do you guys normally source from the LOOP; and the second, do you have any insight as to how BP's oil spill may affect it's operations, meaning, are there scenarios that you know which may cause operations there to be suspended there for some period, and if so what are the parameters and what have you?

Sure, Doug. Great questions.

First of all, we certainly have flexibility. We can source the majority of our crude through LOOP, or we can bring it up the river and unload at our docks, or we can bring some down by barges. We do all of the above, but I would say typically, the majority would come in through LOOP. We have been running -- been keeping a very close eye on the changes in the weather patterns and the changes in the currents, and at this time, we do not expect any interruption of our service. We are in daily contact with LOOP, and they are doing models as well and preparing in the event, but everything looks okay at this time, Doug.

Great. Thanks a lot, Gary.

Next we hear from Paul Cheng with Barclays Capital. Hi, thank you.

I think this is for Dave.

Dave, during the Flying Dutchman and also the other well in the Gulf of Mexico, and another one in Indonesia, any (inaudible) resource base that you can share with us, and also what's (inaudible) net to you on those.

And secondly, for Bakken, the increase in your target weight, maybe you have said and maybe I missed that on the call. Is it a change in your view on the resource base, or just that you are drilling more well and pumping and employing more rig? Thank you.

I think the Bakken question, I'll take first. I think what we've said is we're going to pick up the pace a little bit. We have increased our acreage, and we continue to be pleased with the well results we have. We're really not coming off of our previous views of 350,000 to 400,00 barrels per well, but we are going to get after this a little bit more and see if we can peak up the production there. But all good news as far as that goes.

In the Gulf, I think we previously shared these slides at the various conferences, but Flying Dutchman is a $135 million well, and the gross unrisked potential of that is 100 million to 200 million barrels.

Haynesbrook is, again, right at --

Dane, I'm sorry, $135 million you said net to you, or the gross exposure?

We have 100% of that.

Oh, you have 100%? I thought you only had 63%.

We're basically in an arrangement with another company, but we're going to pay a full $135 million.

Okay.

And the Haynesbrook, we have an 85% interest if that particular well. Again, we estimate about $135 million, and their gross potential there is 75 million to 150 million barrels.

The Indonesian wells, talk about that -- we have a 70% interest in Pasangkayu, as you'll recall. We're thinking those wells will be between $50 million and $60 million, and the target size there is roughly a billion barrels on the first well.

Thank you.

Our next question will come from Doug Leggett with Bank of America Merrill Lynch.

Good afternoon, everybody. I've got two. One and one follow-up. Hopefully that qualifies.

Dave, on the Drosky, you've booked I think about 26 million barrels and you've got $950 million, I'm guessing round numbers, as the CapEx. So the DD&A in this thing is obviously going to be pretty significant. My question is if it come son at 50,000 barrels a day, you're going to eat through that D&A pretty quickly. Unless you book additional reserves, we're going to see some pretty strange numbers as we move forward here. So can you just talk a little bit, what's it's going to take to book additional reserves, what additional costs are we likely to see from a CapEx standpoint to get to the 60 million on Drosky, and maybe a little bit on the production profile would be helpful. And I of course have a follow-up.

Okay. This is not a surprising question.

I think you are absolutely correct, we have 26 million barrels booked. I would think that after -- if we get the rate I've suggested at about 50,000 barrels a day, we'll be able to, on a performance basis, drive those reserve bookings closer to this 60% of this 60 million, or somewhere north of 30, and so I expect that the DD&A rates would start to decline at that point.

What we're looking at basically is we're going to let the reservoir tell us how quickly to ramp up the production, so I won't speculate on how quickly we're going to get to 50,000. As you'll remember when we did Alpine, we got to a peak rate very, very quickly, so we'll certainly try to drive for that. We would expect that rate to be somewhere between -- somewhat less than 50,000 barrels a day through 2011. That will be the strongest production year, and then it will decline very rapidly as we go forward on -- as we deplete the reservoir. Not going to speculate on what else we're going to need.

I think one of the things, the reason why we say we think we've got about $900 million into this, Doug, is we did take one well out of the program that we didn't think that we were going to need. And as you know, in these compartamentalized reservoirs, we're going to have to see -- these are very complicated wells, some with up to seven take-points in them.

So again, the reservoir and how we're draining it will tell us whether or not we need additional wells in order fully deplete this field that we have here. But I would have to say that any activity we're looking that the future would be all drill in bank.

Great, thanks. My follow up is for Gary.

Gary, you give an LLS benchmark. LLS is trading on a substantial premium to WTI. So I guess my question is, with Garyville up and running, you have a lot of flexibility to run different grades, and of course Mya and other heavy sellers are starting to widen out here. What changes have you made to feedstock? Could you kind of give some color around the flexibility and how that's impacting your capture rates, please?

Yes, Doug, great question, and flexibility is the right word. We have tremendous flexibility, and of course we're looking at running a significant portion of heavy barrels, whether they're Mya, possibly some from the Venezuelan markets. We're bringing some Canadian down. So we have very good flexibility for varying types of heavy crude that we're bringing into the facility.

When you look at LLS as a premium, and LLS to MARS is a little over $6 spread today, we certainly are doing everything we can to capture those wider spreads.

Next we hear from Mark Gilman with Benchmark Company.

Folks, good afternoon.

Just wanted to raise a question regarding the impairment on the Powder River Basin. What triggered it, and does this change your future activity in that play at all?

Hey, Mark, this is Dave.

What -- as you'll no doubt, since you've been following this from the time that we made this acquisition almost a decade ago now, there is basically two halves to our Powder River Position. One that's called a fairway that was impacted here, and the remainder of the assets, which were really around Sheridan.

That -- the section around Sheridan is a more standard-type Powder River operation. We're very happy with that, and those operations are going to continue a pace and, in fact, we think that we could produce almost all of the volumes we're taking out of Powder River right now just from that section of the play.

What really drove this was the fairway section was really dependent on the potential development of what we call the Walco, and we've been running a pilot there for a number of years, and frankly have just not been successful getting it to dewater such that it would start giving up gas.

Our view of the technical challenges that were contained in that, particularly with respect to where we see natural gas prices in the Rockies, made this an opportunity that we didn't feel like we could further pursue, and hence the write-down against that asset base.

So I think to that the answer is, is that we're going to consolidate our activities and operations towards the Sheridan side of the play. It will probably be a less aggressive capital and spending profile in the future, and again for the roughly 85% or 90% of the production that we're currently carrying.

So it's going to be an improved business. Certainly don't like to improve businesses in this fashion, but I think we've pursued this as long as we've needed to, and hence the change in direction.

Okay. My follow up is downstream-oriented. Didn't know if I could sneak in a second part. I would appreciate it.

First, I was hoping, Gary, you might be able to explain why it is that you keep citing movements in the Contango, which by the way, at the time I walked into the call was about $3, as a factor in the downstream, if the P-plus pricing-type methodology ceased quite some time ago?

Sure, let me turn that over to Gary who has -- Gary Piper, who has more of the detail with him, as I'm out of town today.

Yes, Mark, this is Gary Piper.

We ceased a while ago synthetic P-plus pricing, that is using derivatives to determine our price for our crude oil acquisitions. When we ceased using synthetic P-plus pricing, we want went to essentially, what the industry calls calendar month averaging, which is through contracts with the producer/suppliers, we essentially replicate a P-plus or a calendar month average pricing which, as a part of the formula, uses market structure to determine the price.

So basically, Gary, the effect is still there?

The effect is still there, we're just doing it without derivatives.

Got it. The follow-up, also downstream.

Gary Heminger, this issue of ethanol blending profitability is an elusive one, and I was hoping maybe you could shed some light on, aside from watching ethanol gasoline spreads, how we might be able to evaluate and and measure it.

Well I would say that is the best way to evaluate that, is looking at the spreads, Mark. It all depends -- to really get into it closer, you have to get in market by market, but the absolute best benchmark would to be look at the spreads in the Gulf Coast and in the Midwest for ethanol to gasoline. I wouldn't have any other benchmark that's better than that.

Gary, could you said any light on that?

Well, no. I think it's a very legitimate question, Mark, we challenge ourselves all the time, because with the advent of a lot of splash blending, that being where wholesalers and jobbers buy the base gasoline and then blend it with ethanol themselves, a retailer, or a jobber, can do his own splash blending and capture those economics himself. So when we look at what we sell as our blended price of gasoline, we have to consider that our customers can do a lot of that on their own. So it really gets really complicated to figure out the price that you're getting for the hydrocarbon, in our case 90% piece, versus the 10% ethanol. So it's a challenge. The biggest challenge you also have is what are you comparing it to, are you comparing it to the 87 octane, or are you just comparing it to the blending components, the blend-grade gasoline that you're using as a blend stock.

So I would advise you, if you're trying to gather some information on this, you shouldn't be using 87 octane. You should be using a conventional blend-grade gasoline to do it with, and there is starting to be more activity in that grade to give you a better feel for the pricing, but it is a very convoluted difficult process to get a grasp on. But I think the point you're trying to make is, if you look a year ago, gasoline and ethanol with the $0.45 a gallon subsidy, 87 gasoline, that is, were selling about at parity. This year, there's about a $0.06 spread. Now, how much of that we actually capture at the rack is very, very difficult for the reason I just stated.

Next we'll hear from Ed Westlake with Credit Suisse.

Actually, hi, this is actually (inaudible )on behalf of Ed Westlake.

Just two questions.

You had mentioned that the Flying Dutchman was coming across as being a challenging well. Is it possible to elaborate on that?

Ye, I think drilling 30,000 feet below 15,000 feet of salt structures is not easy, and I think I've made those comments in the context of we're very proud of our drilling performance, and we've had outstanding performance across all of the metrics. We're certainly being very careful with this well to make sure that we get it down. So nothing abnormal or unusual, just it's taking us a little bit longer than we would have anticipated, I would have anticipated. I'm always in a hurry.

Okay. Thanks. And I just had a quick follow-up.

In regards to the Garyville project, just wondering in current levels of margins and spreads, how does the earning power compare to your expectations that you've laid out in the past?

Well, in the past, in fact we've used a slide in a number of our past reviews, and I'll just say for 2009, the MARS 211 crack spread was $8.83, was the average.And if 2010 were to be the same, we would have a cash flow of about $300 million in profit of 150. I believe in the first quarter our number was very close to $10.50, was the 211 spread. So we're a little bit ahead of where we were in 2009.

Okay. Thank you.

Our next question comes from Paul Sankey with Deutsche Bank.

Hi, good afternoon, everyone.

If I could just ask the first one on downstream. Just to clarify what you said about the LOOP, you said at this time we're not expecting any interruption. Is that like a current day statement, or is it speaking to a week from now, or is it speaking to three months from now? What's the timeframe on that?

And if you could also address how -- what you're best understanding is as to the potential for the Mississippi to be shot, and whether or not, or to what extent that would impact you, that would be my downstream question. Thanks.

Sure, Paul.

As you know how things change in the Gulf, it would be hard to go out beyond a week, but certainly as we look at the current patterns and the work that the -- and the models that LOOP is following and we're following as well, we certainly believe at least a week we're in very good shape.

As far as the river, I think the Coast Guard has done a great job, as well as private industry, and in the event anything would get close to the river, they have stations set up to be able to clean vessels coming up the river, and coming back out of the mouth of the river in necessary. So everything is set up to try to limit any long-term patterns of delay in the river, and at this time, we feel very good about river traffic.

So I would say for the next week or so, Paul, things look good, but its hard to speculate beyond that, as you can understand.

And I guess it's important to keep it open in so far as demands in your mid-Con region is looking pretty strong right now. Are you exporting -- if you could just address the issue you of demand, Gary, by product, the usual question.And just wondering if exports have been a feature of what you've been doing?

Yes, they have. In fact, now with our new plant, we can meet the European (inaudible) spec, and as you know some of Mexico and and some other countries follow the same spec. So we've been selling a number of cargos internationally, as well as we've sold some gasoline on the international market. And we would expect that to continue.

And the demand side locally?

Demand locally, we're up about 1% here in April -- for the month of April, and the first few days of May continue approximately in that same mode.

That's gasoline.

What we're really starting to see, Paul, that I've always said in the past, diesel is the commodity to watch, because we believe that's the commodity of commerce. That's the commodity that is going to help the spreads widen out. And while January and February were negative, March and April have come on both up about 2% and continuing to improve.

So the diesel, like I say, is looking up, and we expect that to continue into the second half of 2010.

That's 2% year-over-year, Gary?

Yes.

Great. I'll leave it there and come back for another one if you want me to move on.

Go ahead, Paul.

Or not.

Operator, do we have another call?

One moment, please.

Hello?

Paul, your line is open.

Yes, it's me again. It's Paul Sankey, again.

Just on cash, is there anything left to say, or to what extent is there more is there to say on the disposal program. And then the usual question following on from that, once you have addressed disposals, obviously you've seen your debt levels come down to very comfortable levels. Can you just reprioritize for us again, especially in light of the positive announcement on Drosky, I guess, where your CapEx might be going from here, and where other excess cash might be going.

Okay. Paul, I'll answer that.

I guess it was just over two years ago that we commenced really a major portfolio optimization program, and as you know, we completed about $3.5 billion worth of asset sales earlier this year.

Portfolio optimization is part of an ongoing business, so we'll continue to look at our assets and determine how we can create greater value by perhaps monetizing some of those assets, but I would say it wouldn't be anywhere near the magnitude of what you've seen the last couple of years.

The cash position, as you noted, is quite comfortable. Our net-debt-to-capital is coming down. It's still early in the year with regard to the capital budget, so, it's still looking like that $5.1 billion, and our priorities in terms of how we employ our cash really are unchanged. It's first to invest in the business and value-accretive projects, and we will continue to maintain a conservative capital structure, and we recognize that the dividends is an important part of total shareholder return, and, as you know quarterly, our Board looks at that. This past quarter we did increase the quarterly dividend by a penny.

So not really much change. Very consistent outlook from a financial perspective.

Next we hear from Blake Fernandez with Howard Wiel. Good afternoon, guys, thanks for taking my question.

The first question I had was on the production profile. Obviously we have first quarter actuals in hand and then second quarter guidance, and full-year guidance implies a very significant ramp in the second half. I know Drosky is coming on-line, but I just wanted to make sure, should we be looking at any other areas that are going to be contributing to growth in the second half other than the I Gulf of Mexico? I know Drosky is coming on-line, but you pointed out some downtime in the second half of the year. I just wanted to make sure, should we be looking at any other areas that are going to be contributing to growth in the second half other than the Gulf of Mexico?

Well, Drosky's going to be the flagship, both in terms of barrels and given where we think crude processing is going to be profitability. But the other thing to remember is we will be bringing on the Expansion 1 in Canada a little bit later this year, so we see some pretty substantial growth exiting the year from that particular asset base.

So you've pretty much hit it. I think the maintenance events that I talked about will probably -- will not be full shutdowns for that period of time, so we certainly have factored that in, and, as I mentioned EG is back and strong as ever, and Norway is producing very, very well, so that with the Drosky uptick should get us to our numbers that we've put out there.

Thanks, Dave, and this one may end up being for you as well, Dave. But I guess one of your larger peers recently announced a very attractive transaction price in the Canadian Oil Sands and I'm just curious if that gives you any new thoughts as to potentially monetizing your asset and redeploying that capital elsewhere.

Yes, we're obviously -- we read the papers and saw that very attractive sale of one of our neighbors down here in Houston. And I think, to Janet's point, we are not in love with any of our assets, and we certainly continue to evaluate how they're positioned for value for our shareholders, either in our portfolio or in a different place.

We continue to believe that the Oil Sands is an extraordinarily attractive and frankly a critical base business for an integrated oil company, and and so we're certainly playing that against what the market possibilities might afford, but having said that, we are open to suggestions, and we would certainly consider that if somebody was interested.

Thanks for your comments. Appreciate it.

Thanks.

Next we hear from Faisel Khan with CITI.

Good afternoon. Question on the Powder River Basin, there any sort of reserve impact from this write-down?

It's de minimis, Feisel. I think the number that's going to come off the books is, I want to say on the order of three million barrels. I think there was a larger impact against the resource potential there, but in terms of what the production impact and the reserve impact was very, very small, because most of our activity in production is, as I said, near the Sheridan area.

Okay. Got you.

And then just on the export question that you answered earlier, Gary, can you quantify how much product you guys are exporting right now?

No. I really don't want to get into those details yet, and we're just have, really just for a couple of months now, had Garyville fully up and running. We continue to do some testing, but I'll be able to give you more guidance on that down the road as we're just starting to get into that business.

Okay. Sounds good.

And then one last question, on your income statement for the first quarter, your segment results, you reported a $102 million benefit for corporate unallocated income tax. I think you may have addressed that in your prepared remarks, Howard, but I was wondering if you could just talk about that again.

Well, that's really related to to the FIN 18 calculations on how we book taxes and what -- nothing beyond that. Just it's consolidation and mix of business that has driven that.

Thank you.

Next we hear from Pavel Molchanov with Raymond James.

Thanks very much.

First just a quick question on the Bakken. Can you give us a sense where differentials are and where you think they might be trending in the back half?

Yes, Pavel. As you know, we typically see differentials between $5 and $7 because of the outstanding work that our marketing people do in the area, and we expect that number is going to be consistent for us on a go-forward basis. So not expecting a broad change there.

Okay. Great.

And then second on Volan, you've been accumulating a lot of acreage. Is this a play where you want to retain 100% or do you plan to bring in a partner?

Oh, I think the position is certainly opportune for partnership activities, because, obviously, we built a position over 1.25 million acres of this particular point at 100% interest, so we'll certainly be looking at those opportunities, but it's fairly early dates.

Appreciate it.

Paul Cheng with Barclays Capital has a follow-up.

Hey, guys, real short question. Janet, at the end of March, what's the underlift, can you give us by region?

Yes, I -- Howard, do you have that handy?

Yes, I have it.

At the end of the first quarter, total year was around 700,000 barrels underlifted. And the EG was about 250,000, BOE, I should say, 250,000 BOE, Libya about 150,000 BOE. I'm sorry, that's the Delta. I apologize, Paul, that's the Delta for the first quarter. That's what happened in the first quarter.

The ending balance, 331,000. About 850,000 underlifted in Europe. There was about 300,000 barrels underlifted in EG, about 300 over in Libya, and about 2.5 million under in Alaska, for a total of around three-three.

Okay. Libya actually is overlifted situation?

Overlifted by right at 300,000 barrels.

And, Howard, based -- I know it's difficult to predict, but based on your current loading schedule, do you guys expect you're going to see those overlift or underlift other than from Alaska to be corrected in the second quarter, or do you think not really?

We don't -- well, it's something -- when you say the lifting schedule, I mean, that is something that's impossible to project at this is point.

I mean, generally we balance out pretty close by the end of the year, but just as this last year, that doesn't always happen. And as you said, Alaska will take quite a while, because that's really gas in storage, is what that is, and it takes a fair amount of time to work that off. But until the end of any quarter, we -- it's impossible to predict, Paul.

Okay. That's fair.

Could I have a follow-up to Gary? Gary, I think part of the reason in the first quarter the result in downstream is poor is because of the timing of the turnaround is in March, pretty heavy concentration, so that -- which is the highest margin in the quarter. Any rough estimate you can share what is the opportunity cost to your operation as we sell off that untimely turnaround operation?

Well, Paul, I -- and in fact I do not have the detail for have we shared the type of detail on opportunity cost, but let me kind of back up and -- most of January and February, in fact all of January and February Garyville base plant, and especially the cat cracker was down.

If you look typically we'll have the base crude unit down just for heater spauling and in the first part of the year, but this year we had the cat down for the entire period as we, as I said, have not had a turnaround for seven years. And then on top of that, we had Texas City completely down (inaudible -- technical difficulties) for March and part of April.

So it wasn't just March, it was very, very large turnaround. In fact, the large turnaround slate that we've ever completed in the Company. And have all of that done now and certainly looking forward to the balance of the year.

And Gary, can you tell me that -- how much of your crude purchase is through the CMA?

Gary, do you have that?

All of our domestic crudes are based on a CMA formula, and roughly -- hold on here a minute -- in the first quarter of this year, about 70% of our crude was domestic. Last year, about 56%.

So about 70% of the crude in the first quarter was on a CMA basis.

And Gary with the Garyville back to full production, should we assume that that percentage is being lower going forward, more like in the 50%, 60%?

That's correct. Yes, that's more our typical, but we're also looking at what type of opportunities we have for international crudes, so part of that reflects the fact that the arbitrage or the domestic barrels were more favorably priced than the foreign barrels. So it's all dependent upon really, economics.

Okay. Very good. Thank you.

We have a follow-up from Mark Gilman with Benchmark Company.

Thanks.

Howard, I believe you mentioned that research and technology technology were down. Can one draw any inference about the Gtl Pilot from that statement?

The Gtf Pilot?

Gtl. We don't have a Gtl, it's a Gtf Pilot. Excuse me.

That's alright.

I'll answer this, Mark.

It is, just to be clear, it is gas-to-fuels pilot, and we completed our testing there at the end of last year, and basically proved the technical concept.

We've gone back into really an engineering phase to see if it can be commercially scaled up, and I think really we've taken the view that that takes a little longer than we would have previously anticipated. And as a result of that, we've take a lot of the capital away from that, focusing on what we think are higher value opportunities for us.

So not a totally positive outlook. Technically, it worked. We're concerned about the ability to commercially scale it.

Okay.

Could I also ask, the foreign upstream tax rate in the quarter at 55% per your statisticle package, was very low by comparison to any prior period, particularly if you take account of the fact that your lowest taxed area in EG was producing at well below normal rates. What am I missing?

Mark, first of all, we base the tax rate on the full-year expectation on FIN 18. So what you're seeing in 2010 is that we have used up the full NOL in Norway, and so, therefore, we don't have to put up any kind of valuation allowance on the resulting US tax credits.

As you recall, in 2009, we were not paying the full cash amount in Norway at 78%, we were paying at 28%. And we -- because we couldn't be certain of the timing of when we would be able to use those tax credits, we had to put a valuation allowance against it. So that's the biggest difference.

So, Janet, in terms of the foreign upstream rate, help me in terms of what would a normal rate, taking that effect into consideration.

Well, Mark, I don't think to we're in a practice of giving a specific rate for a part of a segment. We don't forecast that.

Okay. Thank you.

We have a follow-up from Doug Terreson with Bank of America Merrill Lynch.

Sorry for re-queing, guys, just had a couple of quick things. The Powder River impact, if I look at the US, we see DD&A and OpEx up just a little bit. Could you just give us a run rate as to what we should expect on cash OpEx and DD&A, perhaps also for the international business?

Yes, I can do that, Doug.

I almost spilled my water on the phone, would have cut the call off.

For this year in terms of what our expectations are for field level controllables in our domestic business, we're anticipating a range of $7.30 to $7.80.

Okay.

And on a DD&A rate basis, and again this goes to your Drosky question, the 2010 range is going to be $23.50 to $26.50. Internationally, the same figures. Controllables compared to an actual last year of about 276. We're looking at a range of $2.75 to $3.30. And on a DD&A basis, will be $9 to $10.25.

$10.25?

Yes.

Great, thanks. And the only other one I have is also for you, Dave, if you don't mind. Volan, obviously now onstream, does that mean that you have additional capacity in the FPSO, or does it mean the (inaudible) frame has moved into decline?

Well, as I mentioned, he vessel is sorted for 120,000, and we're producing over that, so we basically are trying to keep full, and we're starting to see some space from Alpine, so it's roughly six months to a year after we thought we would see some declines.

But importantly, Volan has contractual space in the FPSO beginning in July, so this was an event that was coming to us in the next couple of months, in any case.

Great.

At the risk of getting kicked off by your operator, just let me try one final one if I may. Six rigs at the end of the year in the back-end, Dave, any plans to move tha up from six?

No, I think one of things things we're seeing there, is the basinal activity is now over 100 rigs for the industry, which I've expressed to you before, I think that is a real stretch. This is a basin that is comfortable at 90, and we start to see a diminution of performance and I think we can get done what we need to get done with the six rigs we've got, because basically all rigs were built for us by a company we're very comfortable with. And so we'll see, but I don't think you'll see us increase beyond the six.

All right. Terrific. Thank you very much.

Faisel Kahn with CITI has a follow-up.

Just two more follow-ups.

First, for GME, has the tax benefit of that project been fully realized so far?

Gary?

Gary Piper, you want to take that, or do you want me to?

Well, we completed the project in 2009 as expected, so we were eligible to take the 50% bonus depreciation, and so I think the answer is yes.

Okay, so the --

I think there was a small part of capital that didn't get put in place until just after December 31, so there white be a little bit of effect in 2010.

Right, right.

Okay. Got you. And then just on the cash balance, the $2.7 billion that you guys have on cash on hand, your maturity schedule looks fairly light for this year. Can you walk me through again what your priority of the use of that cash is going to be?

Okay. I won't repeat the answer that I gave, I think it was it was to Paul Sankey.

You are aware that we did a premium debt tender here in the last month, multiple press releases put out in that, where we retired $500 million of debt that was, a good bit of it was high coupon legacy debt from the US steel days. On a match maturity basis, it was slightly MPV positive, but more importantly, given that it's very difficult to earn much on your cash balance in this environment, we reduced our negative carry very substantially.

So -- but, again, the priority here is to invest our capital in value-accretive projects in the business, and we're always looking for opportunities where we can capture resource and create value. So that's an ongoing effort. It's not that we set a budget once a year and we live by it for a year. We're constantly looking at opportunities and evaluating those opportunities, and it's great to be in a position where we do have some financial flexibility here.

Thank you very much. I appreciate that.

Mr. Thill, there are no further questions.

Okay, Operator, we appreciate it, and we thank you for all of the interest in Marathon. If you any further questions, please don't hesitate to call Chris Phillips or myself. Thanks and have a great evening.

This does conclude today's conference. thank you for your participation.