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Marathon Oil (NYSE:MRO)

Q1 2010 Earnings Call

May 04, 2010 4:00 pm ET

Executives

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

Gary Heminger - Executive Vice President of Downstream

David Roberts - Executive Vice President of Upstream

Howard Thill - Vice President of Investor Relations & Public Affairs

Analysts

Blake Fernandez - Howard Weil

Pavel Molchanov - Raymond James & Associates

Mark Gilman - The Benchmark Company, LLC

Paul Cheng - Barclays Capital

Faisel Khan - Citigroup Inc

Douglas Leggate - BofA Merrill Lynch

Paul Sankey - Deutsche Bank AG

Operator

Good day and welcome to Marathon Oil's 2010 First Quarter Earnings Conference Call. [Operator Instructions] For opening remarks and introductions, I'd like to turn the call over to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Howard Thill

Thanks, James. I'd also like to welcome everyone to Marathon Oil Corporation's 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 Garry Peiffer, Senior Vice President of Finance and Commercial Services, Downstream.

Slide 2 contains the 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 Privacy and 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 3 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 its details, by quarter, since 2007.

Slide 4 shows the components of the 38% increase in adjusted net income compared to the fourth quarter of 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 E&P production sold. Pretax earnings decreased in the RM&T, Oil Sands Mining and E&P segments. Income taxes decreased as a result of the lower pretax earnings and the adjustment for foreign currency re-measurement of deferred taxes. The fourth quarter included a $139 million loss on the re-measurement 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 U.S. 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 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 5 shows the 14% increase in E&P segment income from $439 million in the fourth quarter to $502 million in the first quarter. The largest impacts were the increase in liquid hydrocarbon and natural gas prices and lower income taxes, largely offset by reduced sales volumes as a result of an under lift in the UK, turnaround activity in Equatorial Guinea and our normal 6% to 8% per-annum production-decline rate.

Slide 6 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 volumes are priced off of Brent, which outperformed WTI during the quarter.

Neither our E&P nor our Oil Sands Mining realizations include the gains and losses on our hedging position. Included in the E&P results were $51 million of net pretax gain on these E&P 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 7 shows the production. Volumes sold in the first quarter 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, primarily driven by the planned turnaround in Equatorial Guinea. The difference in sales volumes and production available for sale was the result of an under lift for the quarter of approximately 220,000 BOE, again, primarily in the U.K.

Turning to Slide 8. While field-level controllable costs were slightly lower from the fourth quarter and exploration expense was down, total expenses per BOE, as shown in Slide 9, increased 6.5% from the fourth quarter, primarily driven by higher DD&A for BOE as a result of volume mix. First quarter E&P 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 realization and lower exploration expense, partially offset by higher DD&A per BOE and other costs.

Turning to Slide 10 in Oil Sands Mining. The segment loss for the first quarter was $17 million, declining $58 million from the $41 million earned in the fourth quarter of 2009, largely driven by lower sales volumes as a result of the planned turnaround activity. Operating and blendstock costs increased $17 million, reflecting $30 million of turnaround costs incurred in the first quarter and a decrease in other operating and blendstock costs as a result of the lower volumes.

Marathon's first quarter 2010 net-synthetic crude production, bitumen, after upgrading, excluding blendstocks, from the AOSP mining operation was up to 21,000 barrels per 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 from derivative activity, which reflects 25,000 bpd of crude oil hedges at $82.56 and it runs through the end of this year.

Turning to Slide 11 and the Integrated Gas segment. First quarter's 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. Because of the seasonality of the Downstream business, I will compare our first quarter 2010 results against the same quarter in 2009.

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. 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 plant 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 stock market refined product markets used in the LLS 6-3-2-1 crack spread calculation used in the first quarter 2010 versus the same quarter in 2009. Partially offsetting these negative effects were increased returns from ethanol-blending activities due to a wider spread between gasoline and ethanol price and the fact that we've blended about 15% more ethanol during the first quarter 2010 compared to the first quarter 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 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 in the first quarter 2010 compared to the first quarter 2009. The increase was primarily due to higher gasoline and distillate margins, which increased from $10.68 per gallon in the first quarter 2009 to $11.95 per gallon in the first quarter 2010. SSA's same-store merchandise sales increased approximately 7% while same-store gasoline volumes were relatively unchanged quarter-to-quarter.

Slide 13 provides historical performance indicators for the Downstream business and previously discussed LLS 6-3-2-1 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 two 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 update. Please remember that on a monthly basis, we update the last page of our Investor Relations packets, which provides the average NYMEX prompt WTI oil price and the 6-3-2-1 crack spread for the Gulf Coast and Chicago markets.

Clarence could not be on the call with us today, as he is in the 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 sectors to control and contain this spill in the gulf. These are difficult and challenging times for us all. As safety and environmental performance is a core value of our company, this event is a source of sadness but also intense reflections on our own businesses to ensure we remain 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 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?

David Roberts

Thanks, Howard. As noted in our release and in Howard's remarks, the upstream performed within expectations for the quarter. We continued 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 plans at Alpine in August, with an expected duration of 14 days; at Point Aven [ph] also in August, with an expected duration of 30 days and at the AMPCO facility in EG in October, with an expected duration of 35 days. These events have been considered in our guidance for the relevant quarters and for the year and we are exploring methods to mitigate their durations.

In terms of new production activities that will allow us to meet the expectations of total upstream production of 412,000 to 438,000 barrels of oil equivalent per day in 2010, I'm pleased to report that Volund began regular production at 13,500 gross barrels oil equivalent 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 gross barrels of oil equivalent per day. All subsea work at Droshky was completed in the first quarter and attention has turned to surface facility completion at Bullwinkle. We expect production in the June to July time frame with Droshky ramping up to 50,000 barrels of oil equivalent per day rates in the later stages of this year.

Our current projections are that Droshky will be brought on stream for roughly $400 million below the sanctioned projections of $1.3 billion. We expect this initial phase of activity will access approximately 60% 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 Innsbruck, two of our planned Miocene target wells in the Gulf, with Bronco [ph], our third operative prospect, expected to spud in later 2010, dependent 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 Ozona project. The Dutchman has proven to be a challenging well to drill, but remains within our timing and cost projections. Innsbruck 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 Pasangkayu Block, the Bronco well will spud in July, followed by the Romeo well in the October time frame. The rig is in transit to the country and will complete its initial well for another operator prior 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 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 and 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?

Gary Heminger

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 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 disintegration 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 a 125,000 barrels-per-day Fluid 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 do some additional maintenance work on this unit to improve its 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’ve performed all of these major maintenance activities under budget in the first quarter. And at the current time, all these refineries are operating as expected.

Turning now to more current events. On the supply and demand front, we have seen improvement in distillate sales throughout our marketing area in March and April. While the increases has been modest, we believe that 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 for approximately 1% here in April.

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

Howard Thill

Thanks, Gary and Dave. Before we open up to questions, I'd like remind to 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 re#prompt for additional questions as time permits. And with that, James, we will open the call up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll take our first question today from Doug Terreson with ISI.

Doug Terreson

I have a question for Gary about refining your marketing. So the first question is A, how much of the feedstock in Garyville do you guys normally source from the loop? And the second is do you have any insight as to how BP's oil spill may affect its operation, meaning are there some areas that you know of which may cause operations to be suspended there for some period? And if so, what are they? Are there parameters or what have you?

Gary Heminger

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 it at our docks or we can bring some down by barges. We do all of the above. Plus I would say, typically, the majority would come in through LOOP. We have 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 that everything looks okay this time, Doug.

Operator

Next, we'll hear from Paul Cheng with Barclays Capital.

Paul Cheng - Barclays Capital

I think this is for Dave. Dave, you're drilling in the Flying Dutchman and also the other well in the Gulf of Mexico, as well as another one in Indonesia. Any kind of pocket resource base that you can share with us? And also, what's the drilling cost net to you on those? And secondly, for Bakken, the increase in your pocket rate, maybe you have said it and maybe I missed that on the call, is it a change in your view on the resource base? Or is it just that you are drilling more well at bopping [ph] and employing more rig?

David Roberts

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 haven't increased our acreage and we continue to be pleased with the well results we have. We're really not coming off of our previous use of 350,000 to 400,000 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. So all good news as far as that goes. In the Gulf, I think we previously shared these slides at various conferences. But the Flying Dutchman's a $135 million well and the gross unrisked potential of that is $100 million to $200 million barrels. Innsbruck is, again, right at...

Paul Cheng - Barclays Capital

$135 million, is that net to you or just the gross exposure?

David Roberts

We have 100% of that.

Paul Cheng - Barclays Capital

You have 100%? I thought you only had 63% on that [indiscernible].

David Roberts

We're basically in an arrangement with another company. But we're going pay a full $135 million. And then Innsbruck, we have an 85% interest in that particular well. Again, we estimate about $135 million and their gross potential there is 75 to 150 million barrels. In 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 we size there is roughly 1 billion barrels from the first well.

Operator

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

Douglas Leggate - BofA Merrill Lynch

Dave, on Droshky, you've booked, I think, about 26 million barrels and you've got $950 million, I'm guessing round numbers, as the CapEx. So that DD&A in this thing is, obviously, going to be pretty significant. My question is if it comes on at 50,000 barrels a day, you're going to eat through that DD&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 going to book additional reserves? What additional costs are we likely to see from a CapEx standpoint to get to the $60 million on Droshky? And maybe a little bit on the production profile would be helpful also.

David Roberts

Not a surprising question because I think you're absolutely correct. We have 26 million barrels booked. I would think that after we get -- if we get the rate that 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 the 60% of the $60 million or somewhere north of $30 million. And so I would expect that the DD&A rates would start to decline at that point. I think 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. And so we'll certainly try to drive for that. We would expect that rate to be somewhat less than 50,000 barrels a day through 2011. That will be the strongest production year. And then it will decline fairly [ph] rapidly as we go forward 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 we say we think we've got about $900 million into this dug 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 this compartmentalized reservoirs in the Gulf, we're going to have to see -- these are very complicated wells. Some of them with up to seven take points in them. And so again, the reservoir and how we're draining it will tell us whether or not we need additional wells in order to fully deplete this field that we have here. But I would say that any activity we're looking at in the future would be all drilling based.

Douglas Leggate - BofA Merrill Lynch

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

Gary Heminger

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 Maya, 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 in to the facility. When you look at LLS has a premium, and LLS to Mars is a little bit over $6 spread today. We certainly are doing everything we can to capture those wider spreads.

Operator

Next, we'll hear Mark Gilman with Benchmark Company.

Mark Gilman - The Benchmark Company, LLC

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?

David Roberts

Mark, this is Dave. 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, it's called the Fairway that was impacted here and the remainder of the assets which were really around Sheridan. 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 in hedging out of Powder River 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 wall coal. And we've been running a pilot there for a number of years and practically just not been successful in getting it dewater, such that it would actually start giving up gas. And I think 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. Hence, the write-down against a bad asset base. So I think that the answer 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 roughly 85% or 90% of the production that we're currently carrying. So it's going to be an improved business. Certainly don't want it to improve businesses in this fashion. But I think we've pursued this as long as we needed to and hence, the change in direction.

Mark Gilman - The Benchmark Company, LLC

My follow-up's downstream-oriented. 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, as of the time I walked into the call, it was about $3, as a factor in terms of the downstream, if the P plus [ph] pricing type methodology ceased quite some time ago?

Gary Heminger

Let me turn that over to Gary Peiffer who has more of detail with him as I'm out of town today.

Garry Peiffer

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

Mark Gilman - The Benchmark Company, LLC

So basically, Garry, the effect is still there?

Garry Peiffer

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

Mark Gilman - The Benchmark Company, LLC

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 gas spread, how we might be able to evaluate and measure it?

Gary Heminger

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'd have to get in market by market, but the absolute best benchmark would be to 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. Garry, can you shed any light on that?

Garry Peiffer

Well, no, I think it's a very legitimate question, Mark. We challenge ourselves all the time because with the added blend [ph], there’s 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 that as economics themselves. 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 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's 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, we're selling about a parody. This year, there's about a $0.06 spread. Now how much of that we actually capture the rack is very, very difficult for the reasons I just stated.

Operator

Next, we have from Ed Westlake from Credit Suisse.

Unidentified Analyst

This is actually Karesh Advani [ph] on behalf of Ed Westlake. Just had two questions. You had mentioned that the Flying Dutchman was coming across as being a challenging well. Is it possible to elaborate on that?

David Roberts

Yes, I think drilling 30,000 feet below 15,000 feet salt structures is not easy. And I think I've made this comment in the context of we're very proud of our drilling performance, and we've had outstanding performance across all 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.

Unidentified Analyst

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

David Roberts

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 [ph] 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 and profit of $150 million. I believe in the first quarter, our number was very close to $10.50 was the 211 [ph] spread. So we're a little bit ahead of where we were in '09.

Operator

Our next question comes from Paul Sankey with Deutsche Bank.

Paul Sankey - Deutsche Bank AG

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 sort of time frame is on that? And if you could also address what your best understanding is if the potential for the Mississippi to be shut and whether or not -- or to what extent that would impact you. That would be my downstream question.

Gary Heminger

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 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, if 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 it's hard to speculate beyond that, as you can understand.

Paul Sankey - Deutsche Bank AG

And I guess it's important to keep it open insofar as demand in your Midcon Region's looking pretty strong right now. Are you exporting it -- if you could just address the issues of demand, Gary, by product, the usual question. And then I was just wondering if experts have been a feature of what you've been doing.

Gary Heminger

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

Paul Sankey - Deutsche Bank AG

And the demand side locally?

Gary Heminger

Demand locally, we're up about 1% here 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's the commodity to watch because we believe that's the commodity of commerce, that's the commodity that's going to help the spreads widen now. And while January and February were negative, March and April have come on, both up about 2% and continuing to improve. So the diesel, as I say, is looking up, and we expect that to continue into the second half of 2010.

Paul Sankey - Deutsche Bank AG

And that's 2% year-over-year, Gary?

Gary Heminger

Yes, sir.

Paul Sankey - Deutsche Bank AG

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

Janet Clark

I guess it was just over two years ago that we commenced really a major portfolio optimization program. 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. We will continue to maintain a conservative capital structure, and we recognize that the dividend's 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 dividends by a penny. So not really much change, very consistent outlook from a financial perspective.

Operator

Next, we'll hear from Blake Fernandez with Howard Weil.

Blake Fernandez - Howard Weil

The first question I had is on the production profile. Obviously, we have first quarter actuals in hand and then second quarter guidance, and then full year guidance implies a very significant ramp in the second half. I know Droshky's coming online. 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?

David Roberts

Well Droshky's going to be the flagship, both in terms of barrels and, given where we think crude prices are going to be, profitability. But the other thing to remember is that we'll be bringing on the expansion [indiscernible] in Canada a little bit later this year. And 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 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 Droshky uptick should get us to our numbers that we put out there.

Blake Fernandez - Howard Weil

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 considering redeploying that capital elsewhere.

David Roberts

Yes, we're obviously -- we read the papers and saw the very attractive sale of one of our neighbors down here in Houston. And I think to Janet's point, we're 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 and at 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 so we're certainly playing that against what the market possibilities might afford. But having said that, we're open to suggestions, and we would certainly consider that if somebody was interested.

Operator

Next, we'll hear from Faisel Khan with Citi.

Faisel Khan - Citigroup Inc

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

David Roberts

It's de minimis, Faisel. I think the number that's going to come off the books is, I want to say, on the order of 3 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.

Faisel Khan - Citigroup Inc

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

Gary Heminger

No, I really don't want to get into those details yet. And we're just -- have really just for a couple 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.

Faisel Khan - Citigroup Inc

On your income statement for the first quarter, in your segment results, you reported $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.

Howard Thill

Well that's really related to the 10.18 calculations on how we book taxes and what's the -- there's nothing beyond that. Just it's consolidation and mix of business that has driven that.

Operator

Next, we'll hear from Pavel Molchanov with Raymond James.

Pavel Molchanov - Raymond James & Associates

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

David Roberts

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.

Pavel Molchanov - Raymond James & Associates

And then second on Poland, you've obviously 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?

David Roberts

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

Operator

Paul Cheng with Barclays Capital has a follow-up.

Paul Cheng - Barclays Capital

Janet, at the end of March was the under lift. Can you give it to us by region?

Janet Clark

Howard, do you have that handy?

Howard Thill

At the end of the first quarter, total Europe was around 700,000 barrels under lifted. 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. That's the delta for the first quarter. That's what happened in the first quarter. The ending balance 3/31 about 850,000 under lifted in Europe. It was about 300,000 barrels under lifted in EG. About 300 over in Libya and about 2.5 million under in Alaska for a total of around 3 3.

Paul Cheng - Barclays Capital

Libya actually is an over lift situation?

Howard Thill

Over lifted by right at 300,000 barrels.

Paul Cheng - Barclays Capital

And Howard, I know it's difficult to predict, but based on your current lifting schedule, do you guys expect you're going to see those over lift or under lift other than Alaska to be corrected in the second quarter or that you think not really?

Howard Thill

Well, it's something -- when you say the lifting schedule, that is something that's impossible to project at this point. I mean generally, we balance out pretty close by the end of the year. But just as this last year, it 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, it's impossible to predict, Paul.

Paul Cheng - Barclays Capital

Gary, I think part of the reason in the first quarter the result in downstream is poor just because of the timing of the turnaround. You've seen March pretty hefty concentration, which is the highest margin in the quarter. Any rough estimate you can share? What is the opportunity cost to your operation as what we saw of that untimely turnaround operation?

Gary Heminger

Well Paul, I do not have the detail nor have we shared the type of detail on opportunity costs. But let me kind of back up. In most of January and February -- in fact all of January and February, Garyville base plant and especially the cat cracker was down. If you looked, typically, we'll have the base crude unit down just for heater spalling in the first part of the year, but this year we had the cat down for the entire period, as we, as I said, had not had a turnaround for seven years. And then on top of that, we had Texas City completely down and Catlettsburg for March and part of April. So it wasn't just March. It was very, very large turnaround, in fact, the largest turnaround slate that we've ever completed in the company. And have all that done now and certainly looking forward to the balance of the year.

Paul Cheng - Barclays Capital

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

Garry Peiffer

All of our domestic crudes are based on a CMA formula and roughly 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.

Paul Cheng - Barclays Capital

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

Garry Peiffer

That's correct. 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.

Operator

You have a follow-up from Mark Gilman wiht Benchmark Company.

Mark Gilman - The Benchmark Company, LLC

Howard, I believe you mentioned that research and technology expenses in the quarter were down. Can one draw any inference about the GTF pilot from that statement?

Howard Thill

The GTF pilot?

Mark Gilman - The Benchmark Company, LLC

GTL.

David Roberts

I'll answer this, Mark. Just to be clear, it is gas-to-fuels pilot. And we completed our testing there at the end of last year and basically prove 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's take a little bit longer than we would have previously anticipated. And as a result of that, we've taken a lot of the capital away from that focusing on what we think are higher-value opportunities for us. Not a totally positive outlook. Technically, it worked. We're concerned about the ability to commercially scale it.

Mark Gilman - The Benchmark Company, LLC

The foreign upstream tax rate in the quarter, at 55% per your statistical 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 below normal rates. What am I missing?

Janet Clark

Mark, first of all, we base the tax rate on the full year expectations, so on 10/18. What you're seeing in 2010 is that we've used up the full NOLs in Norway. And so therefore, we don't have to put up any kind of valuation allowance on the resulting U.S. tax credits. As you recall, in 2009, we were not paying the full cash amount in Norway at 78%. We were payign at 28%. And 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 to against it. So that's the biggest difference.

Mark Gilman - The Benchmark Company, LLC

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

Janet Clark

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

Operator

You have a follow-up from Doug Leggate from Bank of America - Merrill Lynch.

Douglas Leggate - BofA Merrill Lynch

The Powder River impact, if I look at the U.S., we see DD&A and OpEx up just up a little bit. Could you just give us maybe a run rate as to what we should expect on cash OpEx and DD&A and perhaps also for the International business?

David Roberts

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 on a DD&A rate basis. And again, this goes to year Droshky question. The 2010 range is going to be $23.50 to $26.50. Internationally, the same figures, the level of controllables compared to an actual last year of about 2.76. We're looking at the range of $2.75 to $3.30. And our DD&A basis will be $9 to $10.25.

Douglas Leggate - BofA Merrill Lynch

10 25?

David Roberts

Yes.

Douglas Leggate - BofA Merrill Lynch

Volund, obviously now on stream, does that mean that you've got additional capacity in the FPSO? Or does it mean that Alvheim has moved into decline?

David Roberts

As I mentioned, the 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 around the Alvheim Villa [ph], so it's roughly six months to a year after we thought we'd see some declines. But importantly, Volund has a 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.

Douglas Leggate - BofA Merrill Lynch

Six rigs at the end of the year in the Bakken Basin. Any plans to move that up from six?

David Roberts

No, I think one of the things that we're seeing there is the basinal activity, it's now over 100 rigs for the industry, which I've expressed to you before, I think that is a real stretch. I think this is the 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, 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.

Operator

Faisel Khan with Citi has a follow-up.

Faisel Khan - Citigroup Inc

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

Garry Peiffer

Well, we completed the project in 2009 as expected. So we were eligible to take the 50% bonus depreciation. So I think the answer's yes.

Janet Clark

I think there was a small part of capital that didn't get put in place until just after 12/31. So there might be a little bit of effect in 2010.

Faisel Khan - Citigroup Inc

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. So can you just go -- can you walk me through, again, what's your priority of use of this cash is going to be?

Janet Clark

I won't repeat the answer that I give, I think it was 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, a good bit of it was high-coupon legacy debt from the U.S. field aid [ph]. On a matched maturity basis, it was slightly NTB [ph] 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. But again, the priority here is to invest our capital in value-accretive projects in this 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 have some financial flexibility here.

Operator

Mr. Thill, there are no other questions.

Howard Thill

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

Operator

This concludes today's conference. Thank you for your participation.

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Source: Marathon Oil Q1 2010 Earnings Call Transcript
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