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Marathon Oil Corporation (NYSE:MRO)

Q1 2009 Earnings Call

April 30, 2009 11:00 am ET

Executives

Howard Thill - VP of IR

Clarence Cazalot - President and CEO

Janet Clark - EVP and CFO

Dave Roberts - EVP, Upstream

Gary Heminger - EVP and President of Refining, Marketing and Transportation Organization

Gary Peiffer - SVP of Finance and Commercial Services, Downstream

Analysts

Doug Leggate - Howard Weil

Mark Flannery - Credit Suisse

Robert Kessler - Simmons & Company

Erik Mielke - Merrill Lynch

Paul Sankey - Deutsche Bank

Paul Cheng - Barclays Capital

Mark Gilman - Benchmark

Faisel Khan - Citi

Neil McMahon - Sanford Bernstein

Operator

Welcome to Marathon Oil 2009 first quarter earnings call. For opening remarks and introductions, I would like to turn the call over to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Howard Thill

Good afternoon and welcome to Marathon Oil Corporation's first quarter 2009 earnings web cast and teleconference. The synchronized slides that accompany this call can be found on our website, marathon.com.

On the call today are Clarence Cazalot, President and CEO; Janet Clark, Executive Vice President and CFO; Gary Heminger, Marathon Executive Vice President and President of our Refining, Marketing, and Transportation Organization; Dave Roberts, Executive Vice President, Upstream; and Gary Peiffer, Senior Vice President of 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 and the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in it's annual report on Form 10-K for the year ended December 31st, 2008 and subsequent Form 8-K cautionary language identifying the important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Please note that in the appendix to this presentation is a reconciliation of quarterly net income to adjusted net income 2008 and the first quarter of 2009, preliminary balance sheet information, second quarter and full year 2009 operating estimates and other data that you may find useful as there as well.

Slide three, provide net income and adjusted net income data both on an absolute and per share basis. Our first quarter 2009 adjusted net income of $240 million was down 77% from the fourth quarter of 2008 and down 69% from the first quarter of 2008.

The decrease from the fourth quarter was largely driven by the decline in commodity prices, a lower refining and wholesale marketing gross margin and lower E&P production sold. The decreased from the first quarter of 2008 was primarily result of the decline in commodity prices, partially offset by higher E&P production sold and higher refining and wholesale marketing gross margin.

Slide four, shows the decline in adjusted net income from just over $1 billion in the fourth quarter 2008 to the $240 million for the first quarter of 2009. While pre-tax earnings decreased across all segments, income taxes increased primarily as a result of fourth quarter 2008 tax benefits, totaling almost $270 million.

These tax benefits were related to the impact of currency re-measurement on foreign deferred tax liabilities and the full recognition of the Norwegian tax effect of unutilized net operating losses in Norwegian. On a positive note, unallocated administrative expenses decline.

Slide five shows the 62% decrease in E&P segment income from $264 million in the fourth quarter to $100 million in the first quarter. Shown in the waterfall graph are the impacts of the drop in crude oil and natural gas prices and lower liftings during the first quarter, which combined reduced pretax E&P segment income by almost $480 million. These negative impacts were partially offset by lower income taxes, other costs and exploration expenses.

Slide six shows our historical realizations in the $10.86/BOE decrease in our average realizations from $41.59/BOE in the fourth quarter to $30.73/BOE in the first quarter. Our liquid hydrocarbon realizations declined less than NYMEX prompt WTI as about 60% of our global liquid hydrocarbon sales volumes are priced off of Brent, which outperformed WTI during the quarter.

Slide seven shows the production volume sold in the first quarter of 2009 were down 3% compared to the fourth quarter of 2008 to 404,000 BOE per day, while production available for sale increased 7% to 429,000 BOE per day, primarily driven by increased reliability from our Equatorial Guinea and Alvheim/Vilje operations. As well as the return of the remaining Gulf of Mexico production disrupted by the 2008 hurricane.

Additionally, first quarter production available for sale included 5,000 BOE per day from our Ireland operations, which was not included in our previous production guidance for the quarter. The difference in sales volumes and production available for sale created an under lift for the quarter of approximately 2.3 million BOE.

Turning to slide eight. Total E&P expenses per BOE decreased 14% from the fourth quarter, largely attributable to reduced field level controllable, exploration and transportation costs partially offset by higher domestic DD&A per BOE.

A downward revision in proved reserves for Neptune during the first quarter increased DD&A and also led to a charge related to unutilized pipeline capacity. Results reflected $37 million pretax expense related to rig cancellations and excess pipeline capacity charges.

First quarter E&P segment income was $2.74 per BOE, a 60% decrease compared to the fourth quarter of 2008, again primarily due to the lower commodity price realizations.

Turning to slide nine in Oil Sands Mining, the segment loss for the first quarter was $24 million, a decline of $124 million from segment income of $100 million in the fourth quarter of 2008. Fourth quarter segment income reflected a $128 million after tax gain on derivative activity.

Derivatives did not have a significant impact in the first quarter, as we sold additional derivative instruments during the quarter which effectively offset open crude oil positions. All Oil Sands derivatives expire at the end of 2009.

Consistent with the fourth quarter of 2008 net bitumen production for the quarter was 25,000 barrels per day and net synthetic crude oil sales volumes amounted to 32,000 barrels per day.

Average realizations decreased $10.49 per barrel from their fourth quarter level but this was almost entirely offset by a decline in operating cost. The reductions in these operating costs was a result of renegotiated contract services, reduced energy costs and favorable foreign currency movements.

Moving to our downstream business, as noted on slide 10, first quarter 2009 segment income was $159 million compared to a loss of $75 million in the same quarter last year. Because of the seasonality of the downstream business, I will compare our first quarter results against the same quarter in 2008.

The increase in segment income reflects an improvement of over $0.08 per gallon in the refining and wholesale marketing gross margin. This margin increase exceeded the $2.39 per barrel or approximately $5.07 per gallon improvement as indicated in the LLS 6321 crack spread on a two-third Chicago and one-third US Gulf Coast basis, as shown in the historical data at the bottom of this slide.

Because of the difference between our average wholesale price realization and our cost of crude oil and other feedstocks increased more than the year-over-year change in the crack spread.

In addition, manufacturing and other expenses were lower year-over-year due primarily to lower energy and maintenance costs at our refineries.

Marathon's first quarter 2009 refining and wholesale marketing gross margin included pretax derivative losses of $60 million, primarily resulting from mitigation of crude oil inventory price risk exposure.

The first quarter 2008 gross margin included pretax derivative losses of $120 million including the impact of using derivatives to mitigate domestic crude oil acquisition price risk, a practice that the company discontinued during the second quarter of 2008.

Partially offsetting the positive income drivers, our ethanol blending profitability was lower year-over-year, while spot gasoline prices average over $1 per gallon less in the first quarter of 2009 then in the first quarter 2008. Ethanol prices only decreased about half of that amount over the same period.

Total refinery throughputs for the quarter of 1,071,000 barrels per day were consistent with the first quarter 2008 throughputs.

Our retail gasoline and distillate margin slightly decline year-over-year while total sales volumes were flat. However our same-store gasoline sales on a volume basis increased approximately 1%.

Turning to slide 11, in the Integrating Gas segment. First quarter segment income was $27 million, down from $36 million in the fourth quarter of 2008. The quarter-over-quarter decrease was primarily attributable to lower LNG and methanol price realization, partially offset by higher sales volumes in Equatorial Guinea and reduced expenses related to the development of natural gas commercialization technologies.

Slide 12, provides an analysis of preliminary cash flows for the first quarter of 2009. Operating cash flow before changes in our working capital was slightly over $1 billion. Our cash balance was reduced by working capital changes of $497 million primarily reflecting the payment of certain 2008 estimated federal incomes taxes in January 2009.

Capital expenditures during the quarter were $1.3 billion and dividends paid totaled $170 million. We also issued $1.5 billion of new long term debt during the quarter.

Slide 13, provides a summary of select financial data. At the end of the first quarter of 2009, our cash adjusted debt to total capital ratio was 24%, an increase of two percentage points from the fourth quarter of 2008.

As a reminder, the net debt to total capital ratio includes about $480 million of debt service by US deal. The effective tax-rate for the first quarter of 2009 was 49%. However, the expected effective tax-rate for the full year 2009 is in the range of 52% to 57%.

At the bottom of this slide, there is a summary of certain preliminary metrics related to cash flows and usage of cash for the first quarter of 2009 including total capital, investments and exploration spending of $1.4 billion.

Slide 14, sets out our 2009 priorities as Clarence discussed with you on our February 3rd conference call.

And before opening the call to questions, Clarence will make a brief statement.

Clarence Cazalot

Few weeks ago, we announced that Steve Hinchman, Executive Vice President of Technology and Services had elected to retire after 29 years with Marathon. Along Steve's many accomplishments of Marathon, with the expansion of the gas production and liquid processing operations and the LNG Development Equatorial Guinea.

Steve also championed our malaria eradication effort on the Bioko Island, where there's been a 99% reduction in the presence of the malaria transmitting mosquitoes and most importantly almost two fewer infant mortalities per day on Bioko Island.

We want to thank Steve for his tremendous contributions to Marathon, he will be missed and we wish, he and his family all the best in the future.

So Howard back over to you.

Howard Thill

With that said, we'll open the call to questions.

Question-and-Answer Session

Operator

(Operator Instructions) And we'll take our first question from Doug Leggate with Howard Weil.

Doug Leggate - Howard Weil

Good afternoon everybody. I have two questions, if I can take my full quota. The first one is, in your slide pack, you show towards the end, that the operating cash flow in the quarter was about $1.1 billion.

What I'm trying to understand here is what the cash tax implications where in the quarter? Because, we just take the net income and the depreciation, obviously there is a bit of a gap before adjusting for working capital.

So, I guess my question is what is your cash tax this quarter? And what is your expectations for the year, given that Garyville is on stream or on scheduled for the Q4 starts up? And have a follow-up.

Janet Clark

Doug, the cash tax is paid in the first quarter and I don't have all the numbers for you foreign versus US. We do pay lot of foreign taxes Libya get paid monthly and that's a large number right there.

But, we did pay as Howard noted, about $500 million of cash taxes in the first quarter for 2008. For 2009, we did not make a cash, estimated tax payment in the first quarter for US taxes.

Doug Leggate - Howard Weil

Janet, do you expect any cash tax this year. I know that's a hard thing to predict, but I'm thinking really about the tax shield from Garyville.

Janet Clark

Doug, as you can appreciate every quarter, we have to look at that very closely and make the determination of what's the correct amount. Obviously it's probably depended upon, what pricing does and what our downstream business does?

Doug Leggate - Howard Weil

But to be clear, none of the cash tax paid related to 2009?

Janet Clark

In US.

Doug Leggate - Howard Weil

My follow-up is on the production guidance for the year, you've sold what was like about 13,000 barrels per day between the Permian and Ireland and the production guidance looks like it staying unchanged. Alvheim, as I understand, is performing pretty strongly.

So can you just update as that where you see the risk to your production outlook this year, after disposals? Is this effectively, are we leaving the number unchanged despite the sale of 13,000 barrels per day and if so, is the improvement coming from Norway? That's it for me, thanks.

Dave Roberts

Doug, this is Dave. We elected not to change the guidance, largely because we had such a good first quarter and we didn't want to take too much liberty with the numbers. The reliability and operating standards Alvheim and AG both contributed to the outstanding quarter although most of our assets around the world had very good production levels.

There is two events later in the year that obviously we are very focused on and we will take a 10 day turnaround at Alvheim which we're estimating will cost us about 730,000 barrels a day net to Marathon and 320 million cubic feet of gas, we will be taking the facility down entirely for 10 days, so that's certainly an issue.

And then we have a 18 day turnaround schedule for late summer, which will be in Q3 at Equatorial Guinea and that's going to be at 60% range to a 40% reduction over 18 days which equates to about $2.2 billion cubic feet net of loss gas sales, but importantly no liquid effect because we're still be running the gas plant facilities and getting our stripping operations, but we'll lose about 50,000 metric tons of LNG.

Really those are the only two events that I'm concerned about, but in terms of the production capability all time looks very strong. Volund is on track to be delivered, if we need the production in the fourth quarter and that's the reason we were confident on that to say we could extend the 1000 barrels a day we were selling and still keep within the range that we get it.

Doug Leggate - Howard Weil

Great. Dave, just for clarity, where is Alvheim right now in that year?

Dave Roberts

It's running 140,000 gross plus minus, so that's between 75,000 and 80,000 barrels a day.

Operator

Next we'll go to Mark Flannery with Credit Suisse.

Mark Flannery - Credit Suisse

I've got, first question is about cost reductions in the upstream. You've mentioned total expense reduction of about $4 a barrel. Question one is how much more do you think it can go with that? Do you have a target soft or hard target? And the second question is can you talk about cost in the downstream as well? What you're seeing there? What more we may have to go through the balance of the year?

Dave Roberts

I'll start, since you started with the upstream. I think the numbers indicates that like quarters Q1 to Q1, we've seen a 10% reduction in OpEx, in the upstream. Most of that's around contract labor, fuels and lubricants, transportation and logistics.

I should also point out that a significant cost reduction exercise that we already went through was the reduction of our capital budget in the upstream year-on-year, slightly over $800 million. So a lot of the program reductions that you'd see on like-to-like basis have been achieved strictly through straight line reductions.

We also have a program that our procurement group is running in conjunction with the operating divisions to look at capturing cost benefits across the organization. That includes things like obviously drilling completion service again, transportation OCTGs, G&G that type of thing and I think consistent with what other people have been saying. You're seeing spot rates reductions and drilling rates down 30%.

Of course we took the decision sometime ago to contracts for terms when drilling rates were hard to come by, so, we are not seeing a lot of that in our own programs. Certainly work over rig rates down 10% to 30%, drilling services like directional drilling of 15% or more, simulation 25% which is a significant cost savings in terms of our existing capital programs.

We've not set a hard targets in terms of what we think the business should do in terms of the gross number or per barrel basis, instead choosing to just keep the pressure on consistently to make sure that we drive the cost out of our business to prepare for certainly the remainder of this year and for however long this downturn last.

Gary Heminger

And Mark, this is Gary, I echo many of the same comments as Dave, but we are in the same programs with our procurement organization. We have recognized about 7.5% of reduction in cost in the first quarter versus same quarter last year for total of about $85 million.

Good part of that's being energy related and if we look at energy cost staying in this same arena for the balance of the year. We would expect to see some repeatability of those reductions in costs. The balance is in maintenance and other cost items that we are really keeping the lid on those cost.

Mark Flannery - Credit Suisse

Great. Okay. Thank you both very much.

Operator

Our next question comes from Robert Kessler with Simmons & Company.

Robert Kessler - Simmons & Company

Good afternoon, gentlemen and couple of quick ones from me. Firstly, I apologize if you said this and I didn't catch it. At the end of the quarter do you have a number for the net under lift or over left position. I'm assuming you're in the net under lift at the end of the first quarter, but I was curious if you had any order magnitude on that.

And then unrelated to that, I was interested if you had any guidance on the degree of benefit, if any in the quarter on exploiting the Contango shape of the curve?

Dave Roberts

Robert, I'll start with the under lift, as Howard mentioned in his remarks. We were under lifted 2.3 million barrels at the end of the quarter and our expectation in Q2 is that we'll make up 1.5 million barrels of that. My confidence is pretty high, because I've already got 1.2 million barrels made up from a cargo in Gabon that was actually discharged on the 1st of April and a 500,000 barrel cargo from AG as well.

Gary Heminger

And Robert, this is Gary. If you're making an assumption that we run the same crude this year, as we did first quarter last year. The market structure has impacted our cost of crude about $175 million in the first quarter and you look at the Contango is about 435 in the first quarter this year versus a negative, $0.46 or so in the first quarter last year.

So that would be pretty much the structure. However, a caveat I need to put in is you don't always run the same crude and you've seen the differentials narrow from ours (LOS) and some other crude in that same period of time. The peer market structure would amount about $175 million.

Robert Kessler - Simmons & Company

And if I can ask, did you build crude inventories over the course of the quarter?

Gary Peiffer

This is Gary Peiffer, we had a very small amount of crude that put in the tankage for Contango purposes, but actually our crude oil inventories from the beginning of the year to the end of the quarter were actually down overall. So actually have lower inventories for most of the quarter than we expect them at the year end.

Robert Kessler - Simmons & Company

Thanks for that.

Operator

Next we'll go to Erik Mielke with Merrill Lynch.

Erik Mielke - Merrill Lynch

Good afternoon. My question relates to the Oil Sands business, couple of smaller parts to that questions, probably to the one question overall. Firstly, can you just clarify, what the hedging for the remainder of the year is for the Oil Sands business? Have you closed that out completely or do you still have hedging in place for the remaining three quarters of the year?

Secondly, can you talk little bit about the different performance improvement initiatives that have been underway at the Athabasca Oil Sands project I know you're not the operator, but is clearly very material project for you. Finally, can you talk a little bit about the expansion how that's progress obviously the CapEx continues to go out a reasonable rate and I leave it there. Thanks.

Janet Clark

On the hedging is related to the Canadian Oil Sands, we did close out the put positions we have and secondly we sold put that cannot balance the other put. So that you won't see on net side any further hedging gains or losses throughout the rest of the year. We did get about $45 million of cash for sales put. However, we do have calls that are still outstanding that run through a year end at about $90, I believe and its maybe 15,000 barrels to 20,000 barrels a day.

Gary Peiffer

The other two questions, Erik, first of all one the operating cost. We have a very large team working both on the operating cost and to your second question on the CapEx to try to be able to harvest any reduction in cost and improvements and efficiencies.

And I will say making a comparison as Howard, alluded to you in his comments comparing Q1 '09 versus Q4 '08, the reduction in cost are particularly around renegotiating multiple contracts from maintenance to outside services and other categories and labor categories within our operation.

And in addition about a quarter of the cost would have been reduced energy cost and in part of that, that fixed cost that I mention earlier would have also included the optimization of some of our earth moving and tailings.

As far as the expansion one or a little bit over 60% complete with expansion one, little bit ahead on the upstream side versus the upgrader and to your point we are spending ratably as we go through the year.

We would expect a little higher spend over Q2, Q3 because that's when we would have majority of the piping and process unit fabrication to be complete in those good work months or quarters I should say.

Erik Mielke - Merrill Lynch

You're making some progress, if we assume that the progress you've made on the cost side are maintained going forward even this prices we cover from current levels. What sort of oil price does it start to do very great business again?

Gary Heminger

Well, to put our perspective, our total operating expense on a per barrel process basis, the way we do our internal math was about $34 to $35 here at Q1. So, that should put it in perspective for you.

Erik Mielke - Merrill Lynch

Thank you.

Operator

And our next question comes from Paul Sankey with Deutsche Bank.

Paul Sankey - Deutsche Bank

Good afternoon, everyone. Just on Neptune, you mention that was the DD&A impacts, I don't see a volume impacts and that would be the specific part of the question. Could you also talk a little bit more about more generally, what went wrong there, in terms of the news that you've given us today? Thanks.

Dave Roberts

Paul, I guess we have seen volume declines and they won't speak specifically to that. That's seems to be stabilizing a little bit, I think, what we said from the beginning there is that's a very complex and compartmentalized reservoir and we're seeing some of those effects. By and large, we generally would like to throw a questions of that nature to the operator BHP and let them talk about what they're seeing from the performance of the field.

Paul Sankey - Deutsche Bank

I understand. I think that I guess, that was an impact on your DD&A per barrel obviously in the US, you mentioned we also sort of jump in the international DD&A number. Could you just talk a little bit more about what went wrong there? Thanks.

Dave Roberts

I think it's just the effect of Alvheim, you didn't have Alvheim in the first quarter of last year, you had at this year and that's the complete effect.

Paul Sankey - Deutsche Bank

I understand and then if I could have downstream one, Gary, you had quiet a lot of downtime in Q1, are you expecting a better run rate. Could you give us a clue on how much you expect to run in Q2? And I'll ask you the traditional demand question if you could address that as well? Thanks.

Gary Peiffer

Sure. The majority of our downtime was due to plans turnarounds and we just came, are on our way backup with Cabotsburg due to a repair on the pipeline and it wasn't a maintenance issue at refinery, but just to repair on our pipeline. As you know we don't get into specifics as far as turnarounds in the second quarter, but I would say and it all depends on the economics of the plants, but our plants should be in a very good shape on reliability basis and a turnaround basis going into Q2.

Paul Sankey - Deutsche Bank

Gary, I'm thinking the majority of the downturn was turnaround so was that you didn't have any economic downturn in the Q1?

Gary Peiffer

The majority however, depending on the plant and depending on the region there was certainly was some downtime, LLS was much more expensive than WTI in the first quarter. So where we could run WTI we were running flat out and where you have plants that required LLS that were times that we were curtailed.

Paul Sankey - Deutsche Bank

Thanks. Demand?

Gary Peiffer

On the demand side, as indicated in Howard's presentation we were up 1.1% on the same store basis. Here in Q2, it's started out here in April strong up a little bit over 2% on a same store basis within the proxy that we use being our Speedway SuperAmerica same store basis.

However, when I look at our wholesale basis and I'll talk about both gasoline and distillate. Gasoline, on a wholesale side is up probably about a 0.5% across our market but diesel is what could really continues to be hamper, diesel is down about 15% across the complex. It appears as though that diesel has found the bottom and that's over the road diesel which would be at low sulfur diesel.

But when you look at the inventories of high sulfur and low sulfur, diesel is running 35 million to 38 million barrels over same period last year but about half of that being low sulfur and half been high sulfur. So, that's an area that is of much concern to the industry.

Paul Sankey - Deutsche Bank

Great. Thank you, sir. I apologize now if you cover that somewhat in your remarks and I missed it. Thanks.

Operator

And our next question comes from Paul Cheng with Barclays Capital.

Paul Cheng - Barclays Capital

Hey, guys. I think this is for Dave. Dave, you're talking about Neptune I think, you don't indicate that you have a reserve write-down. Can you tell us that how much is that? And also you indicate that 37 million charge, relate to the rig cancellation and the pipeline. I can assume the rig cancellation is a one-off deal and the pipeline is going to be continuing. So, how much is the pipeline piece of that 37 million?

Dave Roberts

Basically, we sanction that the project that slightly over 13 million barrels of reserves. We've produced roughly $2 million barrels that's all net to Marathon and we wrote the reserves down to about $2 million barrels. Again, I am not sure that consistent what the operator and the other partners in the field has done, but that's essentially a 70% write-down.

And the impact of that is as we mention was an incremental DD&A charge over what we expect at about $25 million in the results as reported.

Paul Cheng - Barclays Capital

Dave, is this $25 million in a quarter, I am sorry I missed that?

Dave Roberts

That's $25 million in this quarter and, obviously you expect that to be repeatable and increasing number on a go forward basis. Taking that $37 million, just to break it down roughly $17 million was related to rig cancellation fees, going from two to one rig in the Piceance and 43 rigs in the Bakken.

So, those are our one-time events there was a ship per pay settlement essentially related to the Neptune downgrade of about $9 million and again, we think that's a one-time issue and the remainder of the $37 million is related to an impairment of the Odyssey pipeline which serves the Troika system in the Gulf of Mexico. So the entirety of the $37 million we would not expect to recur.

Paul Cheng - Barclays Capital

If I could have a second question on the capital spending for this year $5.8 billion, Dave and Gary and maybe Janet are you guys seeing any opportunity for same thing due to the declining day rate and the raw-material cost trend or that the entire month is already locked in that fixed contract the assignments you're going to do or those activities there's really not much you can change?

Clarence Cazalot

Paul, this is Clarence. I think we had earlier indicated, we had some $400 million or so of flexibility in that projected capital spend and I think that by the end of the second quarter, we'll be in a better position to give new guidance on that, certainly we believe we're going to be able to pull some of our spending down both in terms of simply what makes sense from a business standpoint and really what we're seeing in terms of a pullback by some of our partners.

Paul Cheng - Barclays Capital

I think it's slightly different question, there is 400 million, I understand there is activity levels, you may reduce your activity, I'm talking about if you don't change your activity how are that 5.8 billion, how much of spend is already in fixed contract and so the change in the raw material and the day rate we're not really benefit and how much of them maybe subject to the spot rate change?

Clarence Cazalot

I would just say Paul, we're not in a position to talk about what we maybe able to pull back on in terms of a lot of the discussions and renegotiations we got. I think by the middle of the year, we'll feel much more comfortable giving you new guidance that would be based both on activity and in terms of any improvements in cost structure that we see.

Paul Cheng - Barclays Capital

Thank you.

Operator

Our next question is from Mark Gilman with Benchmark.

Mark Gilman - Benchmark

Good afternoon. Two upstream points if I could please. Regarding Alvheim, since you've been producing it pretty hard Dave and I guess in that regard I am kind of wondering can the Plato that you're seeing 140 years gross that you refer to. Is that likely to be sustained through the time of Volund start up later in the year?

And related to that back to the international DD&A question, the rate internationally is modestly up from 4Q. Now you book some additional Alvheim reserves at year end, the production mix is not too terribly different 1Q, 4Q on the international side. I would have expected that rate to go down, why didn't it?

Dave Roberts

I'll answer the first one, thinking about the second one. We are planning right now to bring Volund on production in the fourth quarter of this year. I don't think that there is any question that the reservoirs and certainly the production facilities at Alvheim have performed above our expectations.

So the answer to the question, Mark, is I want to be clear that we are not over producing the asset, because it's very consistent with what we think the reservoir models were telling is an appropriate to produce that field. So that's not really an issue and my confidence is pretty high that we'll be able to continue to produce at this rate. It would a good outcome for me, if I have the opportunity to leave all and shut in for period of time.

But time will tell as we get that production on line. Relative to the other question, I think the four-to-one question in terms of DD&A is an under lift issue related to Point Haven and Brae, but it looks essentially the same to us.

Clarence Cazalot

It's pretty flat market, in fact it is to the extent you see any change into this point. Since we are not bringing on any new assets, it's a mix issue. It would be a mix in terms of where the production is coming from, but nothing structural.

Mark Gilman - Benchmark

Thanks very much.

Operator

Thank you. Our next question is from Faisel Khan with Citi.

Faisel Khan - Citi

Good afternoon. Just a follow-up question on Volund. So, I guess right now, in your prepared remarks it says subject to available processing capacity you bring Volund on line. So, given that you're running at a pretty high rate from Alvheim. Are you saying that, Volund could be put off a little bit longer because of the high production rates from Alvheim?

Dave Roberts

It could very well be.

Faisel Khan - Citi

So, then will you just push those numbers back a little bit further or is Alvheim producing at a higher rate than you initially anticipate?

Dave Roberts

Well, it's I think our planning premises were around what's the facility capacity was expected to be at 125,000 barrels of oil per day through the FPSO and what we've indicated is that we've seen rates up to 140,000 barrels of oil. Now that's unusual that our facility would be able to the de-bottleneck, but the testament to the work that our team and (mayors) contract team is doing in terms of de-bottlenecking that facility.

Clarence Cazalot

But, Faisel just to get clear, it's a very good thing that we put on Volund, because it says we're producing Alvheim at capacity, but equally important the reservoir is performing better than we expected. So if we don't need it at year end as Dave said, that's a very good thing. We get the better recovery out of our existing completions.

Faisel Khan - Citi

On the US production side, it came in on the other cost, it was 1250 per barrel versus 1172 in the fourth quarter, and I would have thought that number would have gone down in first quarter, but actually went up.

Dave Roberts

I think Faisel that relates to some of the rig cancellation penalties, we talked about, because that goes in line and that impacts that at all.

Faisel Khan - Citi

Understood, great, thanks for the time guys.

Operator

(Operator Instructions) Our next question comes from Neil McMahon with Sanford Bernstein.

Neil McMahon - Sanford Bernstein

Just a few questions again, maybe going back to Neptune and I know you probably don't want to answer much more on this since you know its operator, but I just wanted to see if I could hear you properly been settled in the UK, was it a 70% or 17% write down on the reserves and versus all of the first part.

Dave Roberts

70.

Neil McMahon - Sanford Bernstein

And you're not taking a book write down on that. You're just increasing the DD&A?

Janet Clark

That's right.

Neil McMahon - Sanford Bernstein

Just to get an idea that's obviously pretty substantial and is this going back to something like a Chinguetti problem from Mauritania, is it basically of the fact that the volumes aren't following through the reservoir properly or is it a total salvageable with a few extra delineation wells.

Clarence Cazalot

I think as we indicated, first of all you're right I'd like for BHP to answer that question but we did for a statement in our release that we do believe the operator is pursuing a number of opportunities to enhance the value of this asset. Chinguetti is a BG asset, so I won't speak to you that.

Neil McMahon - Sanford Bernstein

Well we'll move to a different question on a gas, obviously with LNG price is nothing as strong as they has been, maybe people aren't thinking so much about the second train in AG, just wondered if you could give us some ideas in terms where you've got to in terms of accessing additional gas to actually from second train, there or is it basically getting so complicated in that two region with Nigerian problems that's a big aspiration.

Dave Roberts

I think it's always been a big aspiration, we've never been shy about saying that we would be the first ones to create an internationally volume driven LNG train. I think the first point that you made, Neil, is actually the correct one.

In terms of what we see is global supply overhang in LNG probably is the driving issue in terms of slowing down the progress in Equatorial Guinea. The critical factor and while it is the complex area that government has to put together consortium that is going to help them to drive, the gathering system there which is a critical issue and they are in the midst of a nationwide and essentially a gulf of Guinea, natural gas master plan and that suppose to come out over the foremost of time, we would expect later this year and we will take most specific direction from the government at that time. Just to reiterate the current LNG market does not support getting overly anxious about a second train.

Neil McMahon - Sanford Bernstein

Fine. Thank you.

Operator

We'll go to a follow-up from Paul Cheng with Barclays Capital.

Paul Cheng - Barclays Capital

Hey, guys. Two quick ones, Dave any update about what may be the joint program for exploration for the remainder of this year? Is their other than, I think you probably doing some appraisal for the stone other than your significant exploration well going to be drill this year.

Second, question I think this is for, Gary. I think earlier that you say the cash operating cost is about with $34, $35 per barrel in Oil Sands, looking at the loss and then looking at total synthetic oil sales number. My calculation that simply suggest it's about total unit cost about $53 per barrel and then obviously including DD&A.

So, should we assume that DD&A because of your acquisition is about close to $20 per barrel in here or that I did something wrong in my calculation? Thank you.

Dave Roberts

I will start on the exploration side of things, I think, specifically at the Gulf of Mexico there maybe an outside operated exploration well drilled later this year, as well as an appraisal to Shenandoah, but those plants have not been finalized yet.

And so, I would consider them 50/50 at that particular point. Angola, we have one well down we are drilling one well presently and appraisal well we will have two more exploration well. Other than that we have no major exploration activities for the remainder of the year. 2010 is when we'll get back into the DD&A business.

Paul Cheng - Barclays Capital

Thank you.

Gary Heminger

And Paul to your question, we're in the $50 to $20 per barrel range on DD&A.

Paul Cheng - Barclays Capital

So my calculations on the ballpark correct then. Since that you already have a substantial reduction comparing to a year ago, from the first quarter 2009 cost level should we assume or expect any meaningful cost reduction, sequentially from here for the remainder of the year? Or that this is a reasonable way to assume?

Gary Heminger

As I said earlier Paul, we're going to continue to work on many different sites of the Oil Sands, but also need to be upfront as optimization of tailings and optimization of earth moving will change throughout the year and based on the seasons of which we're in and some turnaround expense that we will have in the Q2, Q3.

So things will change, we will have some plus and some minus, but we are working very, very hard on further reductions that will be repeatable in quarters going forward. This is one very good quarter versus '04 and as we work very hard on this next couple of quarters, I can give you a better trend on what's going to happen.

Paul Cheng - Barclays Capital

Thank you.

Operator

We'll take another follow-up from Mark Gilman with Benchmark.

Mark Gilman - Benchmark

I got to put Mr. Heminger to work for a second or two. Gary I think you answered the prior question and talking to market structure and cited a $175 million benefit. In a situation where you're no longer engaging in the crude role, as you had been previously and we're aggressively putting barrels into storage.

What is that $175 million number really mean? Also Gary, give me a rough ballpark guess as to the percentage of the ethanol blending margin which you retained as oppose to pass through to the customers in the first quarter?

Gary Heminger

Let me answer the second one for you real quickly. I think that is a competitive data that I really don't want to give out to all of our competition, who's either is going on unique basis or selling on a blended basis. So that's really proprietary information. Gary, you want to go into the details on the market structure?

Gary Peiffer

The 175 we point out is the pretax numbers. So that is pretax and as you rightly know, we are no longer using derivatives to price our domestic crude like we did year or so ago. What we are doing is we're buying our crude contractually on what's called the calendar month average basis, where we're essentially using the comps at months price to establish the price for the crude we take title tooling process this month. That's kind of consistent with how we try to price our crude all along Mark, so if you want to price them in the month in which we process them.

When you buy on a calendar month average basis, one of the factors relevance of the formally use to drive the price is the market structure. So to the extent that as Gary said last year first year first quarter, we were in a backward data market about $0.41 a barrel, buy the way this formula works paying more per barrel than the LLS price or WTI price depend upon where you're looking at than what was published.

Now that it's in a Contango market, we're paying this quarter or last quarter about $4.35 per barrel less than the price you see on the screen everyday out there for WTI. So, even though we are not using paper or derivatives to determine our prices, we are doing on contractual basis and the market structure does enter into the calculation of how much we're ultimately pay.

But, as Gary pointed out, that is one of the factor that goes into the calculation how much we pay, and to the extent the differentials change overtime and everything else, you've got to assume to come up with the $175 million figure pretax that Gary talked about. That all the other differentials remain unchanged and they don't.

Mark Gilman - Benchmark

So, Gary if Contango assets obviously have been the case up to this point, now rose from that normally wide first quarter. Then that $175 million all the things being equal is going to diminish considerably in the current period.

Gary Peiffer

That is correct. For us it all other people refiners who buy their crude on a calendar month basis or who use derivative yet to accomplish similar result. Do you think you are alone using this crude pricing practice now?

Mark Gilman - Benchmark

Okay. Thanks a lot.

Operator

Next we go to Mark Flannery with another follow-up from Credit Suisse.

Mark Flannery - Credit Suisse

I would like to get back to this issue of contracted land rigs, which you took the charge in $17 million. Could you give us a feel for of your current fleet of land rigs? How much is contracted and what is the average length of the contract?

Dave Roberts

The rigs that we have now running in the United States in the land fleet, three in the Bakken, one in the Piceance are all term contracts and they will start to roll off beginning of next year.

Mark Flannery - Credit Suisse

Do you have any other such term contracts around the place?

Dave Roberts

Other than Paul Romano of deepwater rig in Gulf of Mexico is under a year contract and obviously we have Jim Bay coming in 2010 but land base rigs is up.

Mark Flannery - Credit Suisse

Thank you very much.

Operator

Thank you. That does conclude our question and answer session. Mr. Thill, I'll turn things over to you for any additional or closing remarks.

Howard Thill

Thank you, Sara for your assistance. We appreciate everyone's attention today. If you have any additional questions, please don't hesitate to call Chris Phillips or myself. Have a great day. Good bye.

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Source: Marathon Oil Corporation Q1 2009 Earnings Call Transcript
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