馬拉松石油 (MRO) 2009 Q1 法說會逐字稿

Good day, and welcome to Marathon Oil Corporation 2009 first quarter earnings call. As a reminder this call is being record. 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.

Thanks, good afternoon, and welcome to Marathon Oil Corporation first quarter 2009 earnings webcast 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's 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 of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10-Q for year ended December 31, 2008, 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 to this presentation is a reconciliation of quarterly net income to adjusted net income for 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 is there as well.

Slide three, provides 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 decrease 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 of 2008 to the $240 million for the first quarter of 2009. While pretax 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 remeasurement on foreign deferred tax liabilities and the full recognition of the Norwegian tax effect of unutilized net operating losses in Norway. On a positive note unallocated administrative expenses declined.

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 listings during the first quarter, which combined reduced pretax E&P segment income by almost $480 million. These negative impacts were partially off yet by lower income taxes, other costs and exploration expenses.

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

Slide seven, shows that 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 productions disrupted by the 2008 hurricanes. 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 underlift 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 cancellation 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, and oil sands mining the segment loss for the first quarter it 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 put 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 costs. 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 margins. This margin increase exceeded the $2.39 per barrel, or approximately $0.057 per gallon improvement as indicated in the LLS 6321 crack spread on a two-thirds 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 feed stocks 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 are ethanol blending profitability was lower year-over-year because while spot gasoline prices average $1 -- over $1 per gallon less in the first quarter of 2009, than in the first of 2008, ethanol prices only decreased about half that amount over the same period. Total refinery throughputs for the quarter of 1.071 million barrels per day were consistent with the first quarter 2008 throughputs. Our retail gasoline and distillate margins slightly declined year-over-year while total sales volume were flat. However, our same store gasoline -- same-store gasoline sales on a volume basis increased approximately 1%.

Turning to slide 11 and the integrated 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 L&G and methanol price realization partially offset by higher sales volume 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 income taxes in January 2009. Capital expenditures during the quarter were $1.3 billion and dividends paid totalled $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 2 percentage points of the fourth quarter of 2008. As a reminder the net debt to total capital ratio includes about $480 million of debt serviced by US Steel. 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 is a summary of certain preliminary metrics related to cash flows and uses 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 3, conference call. And before opening the call to questions, Clarence will make a brief statement.

Thank you, Howard. A 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 with Steve's many accomplishments at Marathon were the expansion of the gas production and liquid processing operations and the O&G development in Equatorial Guinea. Steve also championed our malaria eradication effort on Bioko Island, where there has 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. Howard, back over to you.

Thanks, Clarence. As a reminder to accommodate all who wish to ask questions we ask you limit yourself to one question plus a follow-up. You may reprompt for additional questions as time permits. With that, we'll open the call up to question.

(Operator Instructions) We'll take our first question from Doug Leggate with Howard Well.

I have two questions if I can take my full quota. The first one is in your slide pack you show, I think, 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 were in the quarter, because we just take the net income and the depreciation obviously there is a bit of 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 still, as you put knit your press release, on stream or couldn't schedule for Q4 start-up and I have a follow-up.

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

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

Doug, as you can appreciate, every quarter we have to look at that closely and make the determination of what the correct amount. Obviously it is highly dependent on what pricing does and what our downstream business does.

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

US.

Right. My follow-up is on the production guidance for the year. You've sold it looks like about 13,000 barrels per day between the Permian and Ireland and the production guidance looks like it's staying unchanged, Alvheim, as I understand is performing pretty strongly. So I guess can you just update us as to 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 13,00 barrels per day? And if so is the improvement coming from Norway? That's it for me. Thanks.

Doug, this is Dave. We elected not to change the guidance. Largely because we had such a good first quarter. And we didn't -- we didn't want to take too much liberty with the numbers. The reliability and operating standards at 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're very focused on. We will take a 10-day turn around at Alvheim which will -- 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 a facility down for, entirely for 10 days, so that's certainly an issue. And then we have a 18-day turn-around scheduled for late summer, which will be in Q3, at Equatorial Guinea, and that's going to be a 60% -- at 60% rate, so a 40% reduction over 18 days, which equates to about 2.2 billion cubic feet net of lost gas sales, but importantly no liquid effect because we'll 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 production capability, Alvheim 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 enough to say that we could stand the 10,000 barrels a day we were selling and still keep within the range that we've given.

Great. Just for clarity, where is Alvheim right now net to you?

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

Great. Thanks a lot.

Thank you next we'll go to Mark Flannery with Credit Suisse.

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 you can go with that? Do you have a target, soft or a hard target? And the second question is can you talk about costs in the downstream as well, and what you're seeing there, and what more we may have to go through the balance of the year?

Mark, I'll start since you started with the upstream. I think the numbers indicate that like quarters, Q1 to Q1, we've seen a 10% reduction in OpPex, in the upstream. Most of that is 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, of slightly over $800 million. So a lot of the -- a lot of the program reductions that you see on a like-like basis, have been achieved strictly through straightline reductions.

We also have a program that our procurement group is running in conjunction with the operating divisions, to look at capturing costs, benefits across the organization. And that includes things like obviously drilling completion services, again transportation, OCTGs, G&G, that type of thing. And I think consistent with what other people have been saying, you're seeing spot rate reductions in drilling rigs, down 30%. Of course, we took the decision some time ago to contract for term when drilling rigs were hard to come by, so we're not seeing a lot of that in our own programs, but certainly workover rig rates down between 10 to 30%. Drilling services, like directional drilling off 15% or more, stimulation, 25%, which is a significant cost savings in terms of our existing capital programs. We've not set a hard target in terms of what we think the business should do in terms of a gross number or per barrel basis, instead choosing to just keep the pressure on consistently to make sure that we drive the costs out of our business to prepare for certainly the remainder of this year and for however long this downturn lasts.

Mark, this is Gary. I echo many of the same comments as Dave. We're in the same programs with our procurement organization, but we've recognized about 7.5% reduction in cost the first quarter versus the same quarter last year. For a total of about $85 million. Good part of that being energy related and if we look at energy costs staying in this same arena for the balance of the year we would expect to see some repeatability of those reductions in costs and the balance is in maintenance and other cost items that we're really keeping the lid on, on those costs.

Right. Okay. Thank you both both, very much.

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

Good afternoon, gentlemen, a couple of quick ones for me. I apologize if you said this and I didn't catch it but at the end of the quarter do you have a number for the net underlift or overlift position? I'm assuming you're in a net underlift at the end of the first quarter but I was just curious if you have an order of magnitude on that? 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?

Robert, I'll start with the underlift. As Howard mentioned in his remarks, we were underlifted 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 already got 1.2 million barrels from a cargo in Gabone that was actually discharged on the 1st of April and a 500,000 barrel cargo from AG as well.

Robert, this is Gary, on the -- if you make an assumption that we run the same crudes this year as we did first quarter of last year, the market structure has impacted our cost of crude about $175 million in the first quarter. And, know, you look at the Contango was about $4.35 in the first quarter this year versus a negative, I believe, $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, LOF and some other crudes in that same period of time. But the pure market structure would have been about $175 million.

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

Gary?

This is Gary Peiffer, we had a very small amount of crude that we 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. We actually had lower inventories for most of the quarter than we expect them to end the year at.

Thanks for that.

Thank you. Next we'll go to Eric Mielke with Merrill Lynch.

Good afternoon. My question relates to the oil sands business. Couple of smaller parts to that question, so I'll probably just do the one question overall. Firstly, can you just clarify what the hedging for the remainder of the year is for the year 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 a little bit about the different forms of proven initiatives that have been underway at the oil sands project. I know you're not the operator but it is clearly a very material project for you. And then, finally, can you talk a little bit about the expansion, how that is progressing? I see the CapEx continues to go at a ratable rate, and I leave it there. Thanks.

On the hedging related to the Canadian oil stands we did close out the put positions we had. Effectively we sold puts that counter balanced the other puts so that you won't see on that side any further hedging gains or losses throughout the rest of the year. We did get about 40 million, $45 million cash for the sales input. However, we do have calls that are still outstanding that run through year-end at about $90, I believe, and it's maybe 15,000, 20,000 barrels a day.

Right the other two questions, Eric, first of all, on the operating cost, we have a very large team working both on the operating costs 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 in his comments, comparing Q1 '09 versus Q4 '08, the reduction in costs 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 costs would have been reduced energy costs, and part of that fixed cost that I mentioned earlier, would have also included the optimization of some of our earth-moving and tailings.

As far as the expansion one, we're a little bit over 60% complete with expansion 1. A 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 the majority of the piping and process unit fabrication to be complete in those good work months, or quarters, I should say.

Sounds like you are making some progress. If we assume that the progress we've made on the cost side are maintained going forward even as prices recover from current levels. What if oil prices start to look like a great business again?

What sort of oil price?

Yes.

Oh, well, to put a perspective, our cost here, our total operating expense on a per-barrel process basis, the way we do our internal math, was about 34 to $35 here in Q1, so that should put it into perspective for you.

Thank you.

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

On Neptune you mentioned that was a DD&A impact. I don't see volume impacts and that would be the specific part of the question. Can you talk more generally what went on there in terms of the news that you've given us today? Thanks.

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

I understand. I guess that was an impact on your DD&A obviously in the US, you mentioned that. We also saw a jump in the international DD&A number, could you just talk a little bit more about what went on there? Thanks.

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

Okay. I understand. And then if I could have a downstream one. Gary, are you expecting -- you had quite a bit of downtown in Q1, are you expecting a better run rate, can 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.

Sure. In Q1 we had, you know , the majority of our down time was due to plan turn-arounds and we are on our way up to Cabotsburg due to a repair on the pipeline. It wasn't a maintenance issue at the refinery but just a repair on our pipeline. As you know, we don't get into specifics as far as turn-arounds in the second quarter, but I would say it all depends on the economics of the plants, but our plants should be in very good shape on reliability basis, and a turnaround basis going into

Gary, I'm thinking the majority of the down time was turn-around, so it wasn't you had any economic downturn in Q1?

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

Thanks. Demand?

On the demand side, as indicated in Howard's presentation, we were up 1.1% on a same-store basis. Here in Q2 it started out here in April strong, up little bit over 2% on a same-store basis within the proxy that we use being our speedway supermarket same-store basis. However, when I look at a wholesale basis, and I'm talking about both gasoline and distillates. Gasoline on a wholesale side is up probably about 0.5% across our market, but diesel is what really continues to be hampered. Diesel is down about 15% across the complex. It appears as though that diesel has found the bottom and that is over the road diesel which would be your low sulfur diesel. When we look at the inventories of high sulfur and low sulfur, diesel is running 35 million to 38 million barrels over the same period last year with about half of that being low sulfur and half being high sulfur. So that is an area that is of much concern to the industry.

Great. Thank you for that -- you covered that somewhat in your remarks and I missed it. Thanks.

Thank you and our next question comes from Paul Cheng with Barclays Capital.

Hey, guys. I think this is for David. Dave, you're talking about (inaudible) I think you were going to indicate that you have a reserve writedown. Can you tell us how much is that? And you also indicate that 37 charge relate to the rig cancellation in the pipeline. I presume the rig cancellation is a one off deal and the pipeline is going to be continued. So how much is the pipeline piece of that $37 million?

Okay, Paul, the -- basically we sanctioned the project to slightly over 13 million barrels of reserves, and we produced roughly 2 million barrels that is all net to Marathon, and we wrote the reserves down to about 2 million barrels, and again I'm not sure that that is consistent to what the other operators or what the operator and the other operators in the field has done but that is essentially a 70% write-down. And the impact of that, as we mentioned, was an incremental DD&A charge over what we expected of about $25 million in the results as reported.

That 25 million in the quarter? I'm sorry, I missed that.

That is 25 million in this quarter.

Okay.

And obviously you would expect that to be a repeatable and increasing number on a go-forward basis. Taking the $37 million, just to break it down, roughly $17 million was related to rig cancellation fees going from two to one rigs in the Piceance and 4 to 3 rigs in the Bakken, so those are one-time events. There was a ship or 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.

Okay. If I can 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 saving due to the declining day rate and the raw material cost trend or that the entire money is already locked in with fixed contract of that size you are going to do all those activities, there's really not much you can change?

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 but both in terms of simply what makes sense from a business standpoint and really what we're seeing in terms of a pull-back by some of our partners. So we'll give you--.

Clarence, I think I'm asking a different question. The 400 million I understand there is activity levels, right, you may reduce your activity. I'm talking about if you don't change your activity, out of that 5.8 billion how much of that is already in fixed contract and so the change in the raw material and the day rate will not really benefit you and how much of them may be subject to the spot rate change?

Yes, again, I would just say, Paul, we're not in a position to talk about what we may be able pull back on in term of a lot of the discussions and renegotiations we've 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.

I see. Okay. Thank you.

Thank you . Our next question is from Mark Gilman with The

Guys, good afternoon. Two upstream points if I could, please. Regarding Alvheim, it seems you've been producing it pretty hard, Dave. In that regard I'm wondering can the plateau that you're seeing, the 140ish gross that you referred to, is that likely 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 booked 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?

Okay. I'll answer the first one while I'm thinking about the second one. I think our expectations, we are planning right now to bring Volund on production in the fourth quarter of this year. But I don't think that there is any -- 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 overproducing the asset, because it is very consistent with what we think the reservoir models are telling us is an appropriate way to produce that field, and so that's not really an issue, and my confidence is pretty high that we'll be able to continue to produce at these rates and it would be a good outcome for me if I had the opportunity to leave Volund shut in for a period of time. But time will tell as we get that production on line.

And relative to the other question, I think the four to one question in terms of DD&A is an underlift issue related to Point Haven and Brae. But it looks -- essentially the same to us.

Different.

It is pretty flat, market. In fact, to the extent you see any changes at this point since we're not bringing on any new assets, it is a mix issue. It would be a mix in terms of where the production is coming from. But nothing structural.

Okay. Thanks very much.

Thank you . Our next question is from Faisel Khan with

Hi, Faisel.

Just a follow-up question on Volund. I guess right now in your prepared remarks it says subject to available processing capacity you'll bring Volund on line. So giving 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?

It could very well be.

Okay. So we would just push those numbers a little bit further or is Alvheim producing at a higher rate than you had initially anticipated?

Well, I think our planning premises were around what the facility capacity was expected to be, which is 125,000 barrels of oil per day through the FTSO. And what we've indicated is that we've seen rates up to 140,000 barrels of oil. Now, that is not unusual that a facility would be able to be debottlenecked. But it is a testament to the work that our team and Marathon's contract team is doing in terms of debottlenecking that facility.

Faisel, just so it is clear, it is a very good thing if 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. Getting better recovery out of our existing completions.

Positive problem to have.

Exactly.

On the operating costs on US side, I looked -- looking at your other costs per barrel up to around [1250] in the quarter versus sequentially [1172], I would have suspected that that number would have gone down pretty materially but it actually trended up.

Faisel, you're cutting out. The costs on which side?

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

Yes. I think, Faisel, that relates to some of the rig cancellation penalties we talked about.

Okay.

That goes in line, that impacts that category.

Understood. Great. Thanks for the time, guys.

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

Hi, just a few questions, again. Maybe going back to Neptune. I know you probably don't want to answer much more on this since you're not the operator. I just wanted to see if I could hear you properly, even over in the UK, was it a 70 or 17% write-down on the reserves? First of all that was the first part.

Seven-zero.

Right. You're not taking a book writedown on that, you're just increasing the DD&A?

That's right.

Right, just to get an idea, that is obviously pretty substantial. What -- is this a going back to something like a (inaudible) problem for Martinia? Is it basically a fact that the volumes aren't flowing through the reservoir properly, or is this a total salvageable with few extra deliniation wells?

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

So well, maybe just a different question on gas. Obviously with LNG prices, nothing as strong as it has been, maybe people aren't thinking so much about the second train in EG, I just wondered if you could give us some ideas in terms of where you have got to in terms of accessing additional gas to actually form a second train there? Or is it basically getting so complicated in the natural region with Nigerian problems, that that's a big aspiration?

Well, I think it has always been a big aspiration. We have never been shy about saying that we would be the first ones to create 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 as a global supply overhanging LNG probably is the driving issue in terms of slowing down the progress in Equatorial Guinea. The critical factor, and while it is a complex area, the government has put together a consortium that is going to help them drive the gathering system there, which is a critical issue, and they're in the midst of a nationwide and essentially a Gulf of New Guinea natural gas master plan and that is supposed to come out over the fullness of time we would expect later this year, and we will take more specific direction from the government at that time. But, just to reiterate, the current LNG market does not support getting overly anxious about a second train.

Fine. Thank you.

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

Two quick ones. Dave, on any update about may be the joint program for exploration for the remainder of this year? I there, other than I think you are probably doing some appraisal for the stone, other than that is there any significant exploration well going to be drilled this year? A second question I think this is for Gary, I think earlier that you say the cash operating clause is about 34, $35 per barrel in oil sand. I'm looking at the laws and looking at the totals in oil sales number, my calculation that seems like suggests is about total unit cost about $53 per barrel, and that obviously including DD&A. Should we assume that DD&A because of your acquisition is about close to $20 per barrel in here or did I did something wrong in my calculation? Thank you.

Paul, I'll start on the exploration side of things. I think specifically to the Gulf of Mexico there may be an outside operated exploration well drilled later this year as well as an appraisal to Shenandoah, but those plans have not been finalized yet, so I would consider them P50, at this particular point. Angola we have one well down, we're drilling one well presently, an appraisal well, we'll have two more exploration wells. Other than that we have no major exploration activity for the remainder of the year. 2010 is when we we'll get back into the big E business.

Thank you.

Paul, to your question of we're in the 15 to $20 per barrel range on DD&A.

Okay. So then my calculation is correct then?

You're in the ballpark.

And since that you already have a substantial reduction comparing to a year ago, from the first quarter of 2009 cost level should we assume or expect any meaningful cost reduction sequentially from here for the remaining of the year, of that this is a reasonable rate to assume?

For the oil stands.

Yes.

As I said earlier, Paul, we're going to continue to work on many different side of the oil sands, but also need to be up front 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 turn-around expense that we will have in Q2, Q3. Things will change. We'll have some plus and some minus, but we're 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 the next couple of quarters, I can give you a better trend on what's going to happen.

Thank you.

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

Yes, I got to put Mr. Heminger to work for a second or two. Gary, I think you answered a prior question in talking about market structure and cited a $175 million benefit. In a situation where you're no longer engaging in the crude oil as you had been previously and weren't aggressively putting barrel into storage, what does that $175 million number 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 customers in the first quarter?

Well, 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 is either selling on a neat basis or selling on a blended basis. That is really proprietary information. Gary, you want to go into the details on the market structure?

Yes, Mark, this is Gary Peiffer. The $175 million, I would point out is a pretax number. So that is pretax. As you rightfully know, we're no longer using derivatives to price our domestic crudes like we did a year or so ago, but what we are doing is we're buying our crude contractually on what's called a calendar month average basis where we're essentially using the deposit month's price to establish the price for the crude we take title to and process this month. That is consistent with how we tried to price our crudes all along, Mark. We essentially want to price them in the month in in which we process them.

When you buy on a calendar month base, calendar month average basis, one of the factors or elements of the formula that you use to derive the price is the market structure. So to the extent that -- as Gary said last year first quarter, we were in a backwardated market about $0.41 a barrel, we were actually by the way this formula works paying more per barrel than the LOS price or WTI price, depending upon what you're looking at, than what was published. Now that it's in a -- in a Contango market, we're paying this quarter or last quarter about $4.35 a barrel less, than the price you see on the screen everyday out there for WTI.

So even though we're not using paper or derivatives to determine our prices, we are doing it on a contractual basis and the market structure does enter into the calculation of how much we ought to really pay. As Gary pointed out, that is just one of the factors that goes into the calculation of how much we pay, and to the extent that differentials change over time and everything else, you got to assume to come up with that $175 million figure pretax that Gary talked about that all of the other differentials remain unchanged and they don't.

Gary, if the Contango as has obviously been the case up to this point narrows from that normally wide first quarter, than then that $175 million all things being equal s going to diminish considerably in the current period?

That is correct. For us and all other people, refiners who buy their crude on a calendar month basis or who use derivatives yet to accomplish a similar result.

Do you think you're alone in using this crude pricing practice?

No.

Okay. Thanks a lot.

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

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

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

End of--?

2010.

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

Well, other than the Paul Romano deepwater rig in the Gulf of Mexico it is under a year contract and obviously we have the Jim Bay coming in 2010, but land-based rigs, no.

Okay. Thank you very much.

Thank you . And that does conclude our question-and-answer session. Mr. Thill, I will turn things over to you for any additional or closing

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

That does conclude today's conference. Thank you for your participation.