馬拉松石油 (MRO) 2008 Q2 法說會逐字稿

Good day, everyone. Welcome to Marathon Oil's second quarter earnings conference call. As a reminder, this call is being recorded. For opening remarks and introductions I would like to turn the call over to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you, Jennifer. And I, too, would like to welcome everyone to Marathon Oil Corporation's second quarter 2008 earnings webcast and teleconference. 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 & CFO; Gary Heminger, Marathon Executive Vice President and President of our refining, marketing and transportation organizations; Dave Roberts, Executive Vice President upstream; and Gary Peiffer, Senior Vice President of Finance and Commercial Services downstream.

Slide two contains the forward-looking statements and other information related to 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 10K for the year ended December 31, 2007 and subsequent forms 10Q and 8K cautionary language identifying important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

As most of the numbers we will discuss today are adjusted net income, slide three provides a reconciliation of net income to adjusted net income by quarter for 2006, 2007, and 2008. Slides four and five provide adjusted net income and adjusted net income per diluted share by quarter for 2006 through the second quarter of 2008. Moving to slide six, the year-over-year decrease in adjusted net income mainly resulted from the steep decline in downstream earnings and the derivative impact in Oil Sands Mining partially offset by strong upstream income largely a result of higher upstream liquid hydrocarbon and natural gas price realizations and lower taxes.

Production available for sale increased 29,000-barrels of oil equivalent per day or BOE PD year-over-year largely as a result of a full quarter of gas sale to the Equatorial Guinea L&G plant, the start of production of Alvheim and ramp up in the Bakken Oil Shale resource play. As shown on slide seven, the second quarter 2008 adjusted net income increased almost 12%. for the first quarter of 2008, a result of higher upstream realization and the quarter over quarter improvement in the refining and wholesale marketing gross margin partially offset by the significant decline in the Oil Sands Mining segment.

The Oil Sands Mining segment was negatively impacted by the steep rise in crude oil prices which resulted in a $250 million after tax loss on derivative instruments of which $220 million was unrealized.

Turning to slide eight, upstream segment income for the second quarter was up $144 million over the first quarter 2008, reflecting higher realization while production available for sale was relatively unchanged quarter to quarter. The timing of liftings in Gabon, Equatorial Guinea and Libya and the seasonal injection of gas into storage in Ireland and Alaska, lowered sales volumes in the second quarter partially offsetting the impact of higher realizations.

Slide nine shows the production available for sale and sales volumes just discussed. Average realizations increased 25% for $14.53 per barrel of oil equivalent or BOE between the first and second quarters to $73.26 per BOE. Moving to slide 10, domestic upstream income increased $115 million from the first quarter on higher realizations as well as higher oil volumes in the Bakken Oil Shale resource play and Ewing Bank Block 963. This increase was partially offset by lower gas sales volumes in Alaska, Oklahoma, and east Texas.

As noted on slide 11 both our domestic liquid hydrocarbon realizations and WTI increased by almost $26. Our natural gas realizations in the lower 48 lagged Henry hub pricing, primarily due to weaker basis differentials for gas sold in the mid continent and Rocky Mountain regions. Domestic sales volumes were down in the second quarter largely due to seasonally lower natural gas sales in Alaska. Turning to slide 12, second quarter domestic upstream expense excluding exploration expense increase by $4.54 per BOE for the first quarter from the first quarter, primarily as a result of increased production taxes and increased development activity. Domestic upstream income per BOE increased $10.48 -- reflecting the impact of higher realized prices.

Moving to slide 13, the $29 million increase in international upstream income was the result of higher realizations, partially offset by lower sales volumes which were impacted by the timing of liftings and seasonal gas injection as previously discussed. As shown on slide 14, our total international liquids realizations for the second quarter increased less than Dated Brent. Our international natural crude oil prices actually increased slightly more than Dated Brent NGL realizations did not keep up with the price of crude. Our international natural gas realizations decreased $0.61 per MCF due to the higher proportion of natural gas sales in Equatorial Guinea and lower European volumes.

International sales volumes decreased quarter over quarter to 215,000 BOE PD. And were impacted by the timing of liftings as well as a seasonal decline in natural gas sales in Ireland. Third quarter international sales volumes are anticipated to increase, reflecting a full quarter of production from the Alvheim Vilje development. Additionally, the third quarter is expected to include a make up of a portion of our underlift positions in Equatorial Guinea, Gabon, Libya and at Point Haven.

Turning to slide 15, international upstream income increased $3.42 per BOE, primarily due to higher liquid realizations partially offset by lower sales volumes and higher income taxes. Turning to slide 16 and the Oil Sands Mining segment, the $157 million segment [income] loss was primarily the result of the previously discussed derivative activity. The last of these derivative instruments is set to expire in the fourth quarter of 2009. As you can see in the slide, the derivative losses had a significant impact during the quarter. Net bitumen production for royalties was 24,000 barrels per day for the second quarter which was less than previously guided due to a revised plan to manage the disposal of tailings that resulted in mining a lower grade ore as well as planned and unplanned maintenance at the mine. As shown on slide 17, when you combine our upstream production available for sale and Oil Sands Mining bitumen production, out total production for the second was 398,000 BOE per day an increase of about 15% from the second quarter of 2007 and on par with the first quarter of 2008.

Moving to our downstream businesses, as noted on slide 18, second quarter 2008 segment income totaled $158 million. Compared to $1.25 billion for the same quarter last year. Because of the seasonality of the downstream business, I will compare our second quarter 2008 results against the same quarter in 2007. The primary factor contributing to downstreams lower earnings was a significant reduction in the Light Louisiana Sweet or LLS 6-3-2-1 crack spread. On a two-thirds Chicago, one-third U.S. Gulf Coast basis, the average LLS 6-3-2-1 crack spread decreased by $13 per barrel. In addition, during the second quarter the company's per gallon wholesale sales price realization did not increase over the comparable prior year period as much as the average spot market price for the product in the LLS 6-3-2-1 calculation.

For example, the average price of the products we sell other than gasoline and distillate increased by less than $0.70 per gallon whereas the price of 3% residual fuel oil used in the 6-3-2-1 calculation increased by an average of $0.82 per gallon quarter to quarter. Total refinery crude oil throughput was down almost 50,000 barrels per day for the same quarter last year and total throughput decreased 77,000 barrels per day. We also incurred higher expenses compared to the year ago period, primarily due to higher natural gas prices and maintenance activities. Finally, due to the fact that the cost of our foreign term crude oil purchases rose more in the second quarter of 2008, than in the prior year period, we incurred a pre-tax loss of $156 million on our foreign crude in transit inventories compared to a loss of only $25 million in the same quarter last year.

Partially offsetting these negative factors were several positive quarter to quarter variances. First, our crude oil and other blend stock cost did not increase as much as the change in the average price of LLS during the second quarter of 2008 compared to the prior year period. In addition, primarily because of the widening differential between gasoline and ethanol prices in the second quarter 2008, we had a positive variance in our ethanol earnings during the quarter as compared to the second quarter of 2007.

And finally we improved the volume of refinery gains in our plants in the second quarter of 2008, which along with the higher refined product prices, improved the value of these volume metric gains quarter to quarter. The refining and wholesale marketing gross sale margin for second quarter 2008 includes a pre-tax derivatives-related loss of $187 million compared to a loss of $139 million in the second quarter of 2007. Approximately half of the second quarter 2008 derivative losses were incurred in April as Marathon transitioned away from the practice of using derivatives to mitigate crude oil price risk on our domestic spot crude oil purchases. The downstream business segment will selectively continue its practice of using derivatives to protect the carrying value of seasonal inventories in long haul foreign crude oil spot purchases.

As shown on slide 19, SSA's gasoline and distillate sales were down approximately 40 million gallons or a decrease of 4.8% compared with the second quarter of 2007. While merchandise sales were up 1%. SSA's gross margin for gasoline and distillate was $0.0862 per gallon compared to $0.1029 per gallon in the same quarter of 2007. Slide 20 provides a summary of segment data along with reconciliation to net income. The increase in allocated administrative expenses is primarily due to mark to market adjustments on legacy stock appreciation rights awarded in increased pension expense due to the revision of certain actuarial assumptions.

The effective tax rate for the second quarter was 51% compared to a rate of 44% in the first quarter. The increase was primarily driven by income mix in the upstream segment where Libya took a more prominent percentage in the second quarter compared to the first. The second quarter rate also included a first quarter catch up for the change in rate in an increase in the deferred tax balances related to a change in the Canadian exchange rate. This exchange rate fluctuation was a benefit in the first quarter. Slide 21 provides selected preliminary balance sheet and cash flow data. Cash adjusted debt-to-total capital at the end of the second quarter remain unchanged from the first quarter at approximately 24%. As a reminder, this cash adjusted debt balance includes $488 million of debt serviced by US Steel. Year to date, preliminary cash flow from operations was approximately $3 billion and preliminary cash flow from operations before working capital changes was approximately $2.9 billion.

Slide 22 provides a summary of sources and uses of cash for the first six months of the year. And the impact on our outstanding cash adjusted debt balance. As I stated, operating cash flow from the first half of 2008 was just under $3 billion while capital spending during the period was $3.4 billion. We also spent $295 million on share repurchases and $342 million on dividends. Our net debt increased by $1 billion during the first half of the year. Clarence will provide some comments on the second half of the year later.

Slide 23 provides actual results for the first two quarters as well as guidance for the third quarter and full year 2008. Production available for sale during the third quarter excluding Oil Sands Mining is forecast to be between 360,000 and 385,000 BOE PD versus 374,000 BOE PD available for sale in the second quarter 2008. While third quarter production will be positively impacted by the ramp up of operations that are Alvheim Vilje and Neptune projects, those increases would be offset by scheduled downtime at our Equatorial Guinea LNG and LPG facilities. A planned shut in at Point Haven and a scheduled slow down at the [Sage] facility will adversely affect third quarter production volumes. Additionally, facility maintenance in with Waha's Libyan operations will curtail volumes during the third quarter.

Our upstream production forecast for the full year has been narrowed to 380,000 to 400,000 BOE PD, excluding the effects of any dispositions. The full year production forecast for our Oil Sands Mining segment has been lowered to between 25,000 and 28,000 BOE PD, largely as a result of the previously mentioned revised plan to manage the disposal of tailings. I will now turn the call over to Clarence Cazalot, Marathon President and CEO.

Thank you, Howard, and good afternoon, everyone. Howard has just discussed our second quarter results in some detail. But I now want to comment on Marathon's ongoing plans and activities, and I'll begin with the upstream business and then ask Dave Roberts to provide some additional context and I'll ask Gary Heminger to comment on our downstream activities. Then I'll conclude as Howard has said with our capital and cash flow outlook. It seems clear to me that the market doesn't get fully appreciated. But Marathon's upstream business today is the strongest it's ever been in terms of secured resource and reserve potential and a clear well-defined production growth profile. We also have a high quality portfolio of exploration and other growth opportunities. We are delivering on our defined production growth of 7% compound average growth rate between 2007 and 2012, and I believe both the magnitude and certainty of this growth meets or exceeds that of our peers. Since the beginning of June, we have brought on stream two major high margin projects. Alvheim Vilje, Norway and Neptune in the Gulf of Mexico. Alvheim production commenced on June 8-- considerably later than planned. And we recognize and accept that poor execution on this project despite our best in class execution on EGLNG has hurt our credibility. We have learned some costly lessons and have incorporated these learnings into our project planning and execution.

But I think it's very important that people understand just how well this new asset is performing. The Alvheim Vilje FPSO and related infrastructure have current growth production of almost 100,000 barrels of oil per day and 30 million cubic feet of gas per day from only five wells. And we expect to reach full capacity on the facility in the next few weeks. These are very profitable barrels with an after tax income margin of almost $60 per BOE at $125 WTI. On a total cash basis this asset will generate after tax cash flow net to Marathon for 2008 alone of almost $1.25 billion.

In the Gulf of Mexico the Neptune project in which we have a 30% nonoperated interest has come on stream in early July and has already reached peak capacity of the facility. Marathon's net after income tax margin is $41 per BOE on this project at $125 WTI. Suffice it to say, these two projects will make a significant contribution to Marathon's profitability in the second half of 2008 and beyond.

Importantly, though, we project a substantial increase in our net production available per sale over the second half of 2008, going from a second quarter average of 374,000 BOE per day to an exit rate in December of 425,000 to 450,000barrels of oil equivalent per day. Very significant and profitable growth. Now I'd ask Dave Roberts to provide a little more detail and context around our E&P business.

Thanks, Clarence. As Clarence has mentioned we're on track to reach our target production growth of 7% through 2012. While Alvheim Vilje and Neptune are the 2000 foundation assets for this growth, our line of sight and future potential portfolios continue to suggest a great future for upstream business.

In terms of assets and development [Voland] our next Alvheim area building block is on schedule and will begin production later next year. You will have noted announcing the section of Angola block 31 PSVM project and that production will begin in 2012. And closer still two projects in the Gulf of Mexico, Droshky and Ozona, that we expect to sanction this year will begin adding profitable volumes in 2010 or 2011.

I realize there is tremendous interest in our resource play position. Our 320,000 net acre position in the Bakken Shale of North Dakota continues to deliver. As noted, our net production has already exceeded 6000 barrels of oil equivalent per day and I expect to reach 8000 barrels of oil equivalent per day by year end. We will drill and complete 60 wells this year bringing our totals since entering the play to roughly 100.

In terms of our exposure to other unconventional gas resources, we have full rigs up in the Piceance, Colorado, play and will have 28 total completions by year end with growing production effects in 2009 and Forward Marathon is also building a position in the [Marcella] Appalachia play with 30,000 acres in hand of the targeted 100,000 total by year end. Drilling on our acreage is expected within six to nine months. We already have existing positions in the Hanesville play in east Texas, north Louisiana, 25,000 acres most held by production and drilling will start on in 2009. And the Anadarko Woodford shale in west central Oklahoma where we have 30,000 acres in hand and will have three wells drilled by the end of this year.

Outside of North America we have utilized our experience with [colcine] gas play to capture with our partners green park energy, the largest acreage colcine gas acreage position in the United Kingdom at 520,000 acres, 260,000 net to Marathon. We've drilled three test wells to date and are on the cusp of drilling up to seven pilot production wells in 2008 and 2009. Finally, in the area of unconventional oil we have had encouraging results in the evaluation of two of our oil holdings in Canada. Drilling results from this past winter have bolstered our view of the bitumen source potential in this portfolio. As you recall when we acquired Marathon Canada, we estimated in-situ source potential at 600 million barrels net bitumen. We now believe these assets may approach 1.5 billion barrels net resource potential.

In the 100% Marathon operated Birchwood assets we will likely undertake additional drilling and environmental assessments in 2009. And we expect the project feasibility study to begin in 2009 in Marathon's 20% owned Ells River project. In conjunction with our development projects, Marathon has also positioned itself for long-term success and our exploration program.

While we are now beginning to finally see the results of a long and successful term campaign in Angola, we have been active in securing new opportunities in the Gulf of Mexico where we, along with our partners have been awarded 42 blocks in the last two sales in and Indonesia where we operate the coveted Pasangkayu block and are actively looking for further options there. In the Gulf we have numerous prospects from the recent sale identified and moving toward drillable status in 2009.

Similarly in Indonesia, we have completed the seismic program to over Pasangkayu and will drill our first well there in 2009 as well. But we aren't waiting for the future. We continue to drill successfully in Angola and in the Gulf we are currently participated in the BP operated Freedom well located in Mississippi Canyon block [940A] which will be finished drilling later this quarter. Marathon has a 12.5% interest in this prospect. And in the Anadarko operated Shenandoah well located in Walker Ridge block 8, Marathon has a 10% interest in this prospect. This well spud late in the second quarter and expected to be finished drilling in the third quarter.

Freedom is targeted at the [myocene] and Shenandoah at paleogene, and of course, the shell operated stone side track appraisal will be drilled in the fourth quarter of this year and Marathon has a 25% interest in this lower tertiary well. In addition, we continue to have an active U.S. onshore exploration program in east Texas and Oklahoma. I would remind you that no success from these wells or programs were built into our production forecast. However, if successful they will contribute to our production growth in the future.

In terms of our integrative gas portfolio, while we have made little progress in moving in train two forward as we continue to work on the commercial framework of the project with our partners, our efforts continue in the light of the continued success of train one. With outstanding reliability, the facility continues to meet nameplate expectations and sold in 5800 metric tons of LNG per day in the quarter delivering 14 LNG cargoes.

The facility turnaround originally scheduled for June was started on July 19. It was scheduled for 16 days, but the facility has already returned to 50% capacity and should be at 100% on the weekend. Quite simply EGLNG is an industry leading operation. Our other integrative gas businesses had solid quarter two, but our methanol business experience a 30 day shut down to begin quarter three due to a process issue; the facility has been returned to production. Clarence, I'm sorry, I perhaps carried on a bit longer than I should have, but we have a great story for the quarter and for the future in our upstream portfolio.

Thank you, Dave. Now, I'd like Gary to update you on the downstream.

Okay and I believe Howard covered in sufficient detail the results of the second quarter, so I'll just bring you up to date on a couple of our major projects and then talk a little bit about the current market. But on our first project, the Garyville major expansion, we are approximately 60% complete as we speak today, and we have a full compliment of skilled trades across the entire mechanical civil side of that construction project. We are beginning to take delivery of some of the major fabricated vessels. In fact our Coker as we speak is coming through the Panama Canal. And we continue to expect fourth quarter 2009 start up. And as I said we are on time and on budget. Turning to the Detroit heavy oil upgrade project we did receive our permit and on April, excuse me, on June 20 and started construction immediately. We've just started the construction side of that business of only 5% complete. But we will significantly wrap up over the coming months.

Turning then to the operations, while markets have been challenging in the second quarter with a run up of $40 in the crude price, I am pleased to state that we have operated above our plant from mechanical availability standpoint and from a safety standpoint. When you look at today's markets, and look at Speedway Super America same store sales, we believe that we have outperformed the overall market when we look at same store versus pad of two total demand. So from an operating standpoint we are operating well; we're getting our products into our marketplace, and we are continuing to add new Marathon brand of business which will help down the road with our Garyville major expansion program. And with that Clarence, I'll turn it back to you.

Thank you, Gary. Our overall 2008 capital spending will be up slightly. As we have reduced spending in the downstream and increased spending primarily in the upstream. From a cash flow standpoint we expect cash flow from operations in the second half of 2008 to essentially cover our capital spending, dividend payments, and share buy back program. In addition, our portfolio review process will result in the sale of certain assets.

As announced earlier this month, we have reached an agreement with Centrica to sell our nonoperated interest in the offshore Heimdal infrastructure and related fields for $416 million. We expect to announce additional sales in the third quarter. Lastly, you no doubt saw our announcement this morning that our Board is evaluating a potential separation of Marathon into two strong independently -- independent and publicly traded companies, and I know you have some questions, and we will try to be as responsive as we can, but I hope you understand that we probably can't be much more specific than what is in the release. And with that, I will turn it over to Howard for questions.

Thank you, Clarence. Dave and Gary, appreciate that update. Before we open it up to questions, I would like it to remind everyone that to accommodate all those who want to ask questions with the limited amount of time we have remaining, we'd ask that you limit yourself to one question plus the follow-up. And that for the benefit of all of the listeners we'd ask that you identify yourself and you affiliation and with that, we will open it up to questions, Jennifer.

Thank you, sir. (OPERATOR INSTRUCTIONS)

And we'll go ahead and take our first question from Arjun Murti with Goldman Sachs.

Thank you very much. Clarence, I definitely appreciate that there are probably legal restrictions beyond the press release, but just want to try one related to the press release. You mentioned that you didn't think the Street was fully appreciated of the value of the EMP business. Is the primary driver of the separation here belief that the stock is very undervalued? Or were there thing strategically that either business couldn't do together that they could potentially do separated? And I guess my thought there was it hasn't seemed like there was anything strategically either that refiner EMP couldn't do as part of a combined company, and therefore, I presume the driver here was valuation and perhaps you could shed some color on that.

Arjun, I think you summed it up front. There is only so much at this point prior to actually completing the evaluation and disclosing the decision that we really want to say, but suffice it to say, ours is a management of the board as I said many times before that is always looking to see what we can do to enhance our business. Strategically operationally and financially.

I think, as you would expect, we continually look at all of the options and alternatives available to us. And this is one as we said in the press release that we have been looking at for sometime now and have now advanced to the point that we have brought in outside advisers, and I think you should put great importance around the fact that we have done that and we have also said that this will be completed and the board will make its decision in the fourth quarter. And I think at this point, Arjun, we prefer to wait until a decision is made and then talk about it much more fulsomely in terms of what actions are actually taken.

Thank you, Clarence. If I could ask one related follow-up and it's really just a clarify something I think you just said, and I believe you said in the past and that is you are looking to do what's right for shareholders and get the most value possible. Which would mean all options are available. The press release specifically refers to a potential separation, but I think Marathon has always considered all alternatives which could be, obviously, a sale of the entire company, sale of individual pieces, keeping the company together. I think you are willing to consider all alternatives, is that correct?

That's the process that is always on the table. And constantly reviewing our options. Yes.

Thank you very much.

We will go ahead and move to a question with Paul Sankey with Deutsche Bank.

Hi, Clarence. Thanks for taking the question. If I could follow up on the all options are open angle. It nevertheless seems that the way you've written the press release indicates that the strategic option is going to be quite clearly outlined in terms of the split between upstream and downstream and that's going to be the nature of the vote by Q4 or am I reading too much into the way you written the statement? Thanks.

I think the statement is pretty clear, Paul. It says that we have undertaken an evaluation of a potential separation of the company into two separate publicly traded entities, and suffice it to say, that as we have looked at our options and alternatives that is one that we have elected to go forward and study in greater detail and because we want to ensure that we're able to do that, fulsomely engage the people that need to be in that evaluation we felt it was important to announce it and let people know that indeed the board had elected to go forward with this detailed evaluation.

Basically you still finalizing the split of assets. The reason I'm asking this is because you can debate whether or not the Canadian heavy oil sands should stay within the downstream whether or not you should slip her refinery into an upstream valued company. And other issues such as that.

Yes, there are a lot of things, frankly, Paul, that need to be decided, and obviously, that's why we are limited in terms of what we will say today. We did say however that the businesses -- the current business segments that would be combined would be expiration, production, integrated gas, and the Oil Sands Mining business with the refining, marketing, and transportation business being a separate one and that's simply because as we look at where the businesses best fit, we think Oils Sands Mining fits better with the upstream in part because of what Dave indicated earlier that we now see greater potential in the in situ resource than we did at the type of the acquisition, and obviously, that lends itself to upstream type skills sets and technologies. But also, I think as everyone is aware the SEC is there looking to finalize their thoughts on reserve estimation and estimates is certainly now looking much more seriously at classifying mining reserves as convention -- not conventional but as oil and gas reserves. So we think it makes more sense there. I know other companies do it differently, but that's the fit we think is most logical. Again, if indeed a separation were to occur.

And just very finally, I guess on timing we can be relatively confident of a vote in Q4. There's no reason to believe that there would be any drift in the way that we have seen another corporate action sliding in other oil companies?

You know, we wouldn't have said it in our press release, Paul, if we didn't mean it. That's what we said.

Thanks, Clarence.

All right, we'll move forward and take a question from Neil McMahon with Sanford Bernstein.

Hi. Just another question on the potential separation. How do you view your position in the Canadian Oil Sands with respect to the availability of refining capacity for any additional volumes you would bring on into the future outside your capacity that you've already been allocated within the shale upgrader? Maybe walk through if any deal were to happen, would there be certain requirements or contracts that you would still have effective capacity in the [ex-marlabolo's] refining portfolio.

You know, Neil, that's again one of many details that would be part of this ongoing evaluation. But certainly we would have before us the option if we believe it to be in the best interest of the company itself to have some kind of supply agreement between the entities. At this point we are not prepared to say that is something that we would or would not do. It is an option and it's one of the things that will be studied.

Maybe in a related question, Clarence. Given the fact that the share price of the company has been suffering for sometime, have you seen any interest from other parties, in Marathon as a combined entity? Has that sort of fished you and the board to actually look at maybe splitting up or taking on a different tact? Or is this something that you say has been going on over the last few months. I was just wondering if there was anything else that may have started you down this process.

Neil, if I'm nothing, I'm consistent and I've consistently said on these kinds of questions and we don't comment on those kinds of things. As we said before, the valuation that we undertook internally started several months ago. Again, that is something that we undertook on our own. But we don't comment on contacts or discussion with other companies.

Okay. Thanks.

Okay.

We will take a question from Paul Cheng with Lehman Brothers.

Hey, guys.

Hello, Paul.

I guess I should not ask any more question about the separation.

You could, but you may not get an answer.

I probably save that. Gary, can you give us some market intelligent that how the diesel sales look like on same store sale in terms of diesel?

Sure. In the second quarter, Paul, we found a slow down in same store diesel around a-- I would say a 4 to 4.5% across the board. Most of that caused by two reasons. First of all, a drop in tonnage in the market. And secondly, the way the rig operators are now running their trucks, and if you are out on the interstate at all you will see they are running in a much lower speed than they had prior which has really taken about an improvement of about 4% in their miles per gallon which has dropped demand. So to answer your question in the 4 to 4.5% percent range.

Maybe directly related to separation with today's credit and also the, I guess the higher prices, if the -- independent company what kind of working capital requirement or financing need will there be? How big is your credit line need to be?

Again, Paul, you ventured into an area that again part of the evaluation would be to ensure that if indeed a separation is implemented that both companies are investment grade and fully capable of handling all of their capital and funding and working capital requirements. So again, I don't want to speculate about those kinds of things. Suffice it to say that's part of the analysis that will be done.

Okay. Thank you.

Our next question comes from Doug Leggate with [Caden] Capital.

Hi, folks. Are you doing?

Good, Doug.

I'm going to try a couple on you, Clarence. I'm not going to talk about separation too much. You mentioned on the-- or Howard mentioned on the introductory remarks about the fall in production in the third quarter partly been related to Equatorial Guinea. What I'm curious about is some idea what the -- there is because if I'm not mistaken these are low margin upstream barrels and at the same time you will be ramping up barrels that you basically are telling are going to earn $60 per range per barrel. So can you give us an idea of how much the volume impact is likely to be Q3 of the (inaudible). Then I have a follow-up.

This is Dave Roberts. As we talked about we had basically a 16 day turnaround in the LNG facility, and I think as we talked in the last quarter, you can imagine that about a 30,000-barrel a day drop, 25,000 of that being natural gas, 5000 of it being liquids. We think for the quarter that that's going to be slightly over 10,000 barrels a day. And I would remind you that even though the natural gas is low volume, it's turned into LNG which low value and turned into LNG that we do take value out of and integrated gas segment.

Great. Thanks for the volume number. My follow-up is I guess there's been no updates on the disposal program that you folks are targeting in the second half. If you could bring us up to date there that would be great.

Thanks. There is not much to say other than what I said in the comments that we concluded the sale of the Norway assets, and you should anticipate additional asset sale announcements in the third quarter. We are moving forward on our asset review program, and the sale of those assets that we deemed to be noncore to our company.

Do you think that two to four is still a good number to be realized this year?

It's the number we said in terms of what would be concluded by the middle of 2009. So I think the numbers still valid and the timing still valid.

Great stuff. Thanks.

Take a question from Michael LaMotte from JPMorgan.

Thanks. Good afternoon, everybody. Clarence, if I could sort of beat this horse, hopefully, not dead on the separation. I think we've largely assumed a complete separation, and if I look at the value of integration in terms of supply agreements and the CapEx requirements on the downstream into '09 and in 2010, the upstream was providing a good bit of cash into those investments, is one of the options on the table here just perhaps an IPO of 20% of the upstream business to try to get a re-valuation but not -- or is the ultimate end game total separation.

I think I will again let the press release speak for itself. We are looking at the potential separation of two businesses. Beyond that, we are not speculating on IPOs. We're not speculating on the funding ability or debt levels of the various companies. Those are all details to be dealt with as we go through this process. But again, as I said earlier, suffice it to say if this were something that the evaluations said we should do, you can rest assured that we will do it on a basis that both companies would not just be operationally strong, but financially strong and able to take care of again all of their funding requirements. You can take that as a given.

Okay. So the takeaway is really all options are on the table at this point?

I'm not sure all options. We said we are evaluating a potential separation of the company. Within the context of that separation, there are a number of options that we could pursue, and so yes, within the context of that, we are looking at many, many options. So, yes.

And then to follow-up on Doug's question on at specific assets, if I look at your positions in Hanesville and Woodford, they are relatively small particularly versus some of the EMP companies. Do you see yourself as the net buyer or seller of acreage in those two plays.

Michael, this is Dave Roberts. I think there are a couple of things. Number one, is we have no aspirations to be like some of our independent competitors in terms of having massive land position. What you see in particularly in the Anadarko Woodford is we have a very focused and we think very core position. But I think going to the overall philosophy of Marathon is we are going to do what's best for our shareholders and that may include coring up in some of these basins and leaving others.

Okay. Helpful. Thank you.

All right, we'll go ahead and take our next question from Erik Mielke with Merrill Lynch.

Following up on the very comprehensive update you gave on the upstream business and whether different projects on the ramp up through the second half of the year, the one part of the business that hasn't performed as one would have hoped is the Oil Sands business. Can you talk a little bit about the possibility when you are operating at these 25,000 barrels per day, therefore, and what that does to operating cost? Because it seems that you are not really getting a huge contribution from that segment.

This is Gary. Let me put that in perspective and go over our cash operating cost. I was anticipating that question based on the performance in the second quarter and just let me state that Marathon Oil Canada's cash operating costs were in the $40 to $45 range for the second quarter versus $35 to $40 per barrel in the first quarter. And it's higher Op Ex is primarily due to higher cost of natural gas, diesel, electricity, and then the plan and unplanned maintenance that we talked about before. Specifically, also the execution of our tailings management plan.

So when you look at those costs and we compare those against some of our major competitors, we blend -- we have a different operation some of our major competitors in the Oil Sands in that we blend a rather large amount of feed stocks in order to be able to make the oil sand available for market sale. So we have a little bit of a different manner which we calculate this. But we have subtracted those purchase feed stocks out. So if you look at versus the first quarter, we were higher than our operating costs in the first quarter. But there are two things that went on. First of all the grade quality here in the second quarter, we were just finishing up one the base cells of production, and as we were finishing that base cell up, we of course ran into much lower ore grade quality. Still moving the same tonnage per day, the lower ore grade quality. Now that we have completed that right at the first of July, we are moving in to a new area of the cell and expect to be able to prove on that as we go into the third quarter.

And then lastly, as we have really ramped up the execution of a temporary tailings management issue, we believe that will help us going into the second half of the year as well.

I will just say on, Erik, on our slide 16 what we have tried to illustrate is what the overall profitability is in that business if you exclude the unrealized derivatives and would have been $63 million in the quarter and that's a quarter as Gary said because of this tailing management program and dealing with the poor ore grade, our volumes were down. And again I think the team is working well together, Chevron, Chevron, Marathon, both in terms of improving that as well as the overall reliability of the system. So I wouldn't be too disheartened by near term performance great asset that's going to be a significant contributor for us.

Great. Looking forward to say maybe two quarters and you have everything up and running again and assuming a similar presence of what we had in the second quarter. Would picks of 35 be realistic?

Well, we have not completed nor has the operator completed next year's plan. As we came into this year, and we were expecting somewhere in the somewhere to 30 to 33 range and have been disappointed in the performance as Clarence and I just outlined. So we'll see that the operator puts forth the 2009 business plan, but let me put it this way, we will be very disappointed if it wasn't north of where we are this year.

Thanks.

Move to a question from Faisel Khan with Citigroup.

Good afternoon. Wondering if you could just comment on the start up of the construction on Detroit in terms of what type of contingencies you guys have planned in terms of cost inflation and labor inflation for the cost for that project.

Okay. This is Gary. Just starting up here and please understand we are just in the early stages of the civil work and we are in negotiations with some of the main fabricators and some of the main contractors so I really don't want to get in and discuss any contingencies. The number that we put out is that this is a $1.9 billion project. We believe we have adequately fully covered what the critical skills, the fabricating cost, and the materials will be in that project.

Fair enough. And then on the refining business I know you guys have talked about kind of your ability to have discretionary blending of ethanol. Can you talk about in the quarter what kind of advantage or disadvantage that may have had for you in the quarter in terms of blending ethanol.

Gary? Gary Peiffer's on the line, do you have any -- I don't have those details with me.

Yes, this is Gary Peiffer. I guess the only thing we don't really talk about our ethanol profitability. But what I can tell you is in the quarter, blending of ethanol was up versus our prior years such that we blended about 55,000 barrels a day of ethanol in the second quarter of '08. That compares to about 40,000 barrels in the second quarter of '07. So substantial increase in the amount of ethanol we're blending.

We believe that because of the infrastructure which we invested in, we are now capable of blending up to an E-10 blend, 10% ethanol, 90% gasoline throughout our entire marketing net work that we are able to take advantage of the fairly substantial difference that is in the market today between ethanol prices and gasoline prices. So just the sheer volume of increase that we've had over the last year plus the positive variance we've had because of the pricing has given us we think a pretty strong advantage in our ethanol blending program this quarter.

Great. Thanks for the time.

All right, we'll go ahead and move to a question from Robert Kessler with Simmons & Company.

Good afternoon. Sorry, I've got another separation question. This is one area where you seem to have honed in fairly specifically on which is the separation into two big buckets. That being as opposed to multiple smaller buckets. I'm curious if you can comment into why you have gone ahead and made that decision at this point in the valuation process. A couple things that come to mind would be I'm sure you have been pitched countless times in the downstream on spinning off your mid-stream transportation assets into an [NOP]. I know you have not been particularly keen on that idea in the past, but it does imply a multiple gap that could be realized and as a consequence you can accelerate value there. And then in the upstream it seems you have a number of big assets that would be attractive to your major oil peers perhaps independent of the other assets.

Certainly, you've already commented about breaking apart the downstream from the Oil Sands, the majors outside of your cells have been quite keen to pick up oil sands companies in isolation. And then on integrated gas you've already highlighted your interest in farming out perhaps EGLNG to tie in some reserves held by others there which would indicate perhaps that being a possible separate divestment candidate. And then finally in Angola it's a nonoperated interest largely. I know those partners are quite keen on their own or interested in expanding their own interest there so perhaps selling to your partners in Angola would make sense. Seems you've excluded those options at a fairly early stage. I'm just curious as to why.

I guess, Robert, first of all I would say, that as we have said now for sometime we had an asset review program underway, and you saw the first result of that in the sale in Norway. And as I indicated earlier we anticipate additional sales to come. So I think clearly there will be other assets that we don't see as part of our ongoing portfolio either as a combined entity or in separate companies. I think that we are in the business about creating value, and I'd say that the combination of the assets that we have indicated thus far in our press release give us the best opportunity we believe to do just that.

And are there other potential combinations? Perhaps, you've indicated some. We think that when we look at the aggregation of our assets in our downstream business to your point, we have a great set of assets from our refining assets to our mid-stream assets to our marketing assets. Our teams -- our management teams will continue to look at what they can do to capture the most value from those. And in the end, if we decide to separate into separate companies that will be an issue for the new management and board to consider whether or not MOPs are part of their strategy. Again, I don't want to presuppose anything along those lines.

But I will simply tell you that we are a management team that indeed continually assesses how we best build our business to create value and some of the things you've discussed would not be foreign to us. But we have indicated in our press release what we believe to be the best aggregation of assets going forward.

Thanks, Clarence. If I could ask one quick follow-up just a quick numerical one. On the mid-stream business, do you have an estimate of EBITDA just for your mid-stream assets?

No, we did not make that public.

Thanks.

We will take a question from Mark Gilman with the Benchmark Company.

Good afternoon, folks. I wanted to talk a little bit about plateau production and the ability to sustain at both Neptune as well as Alvheim. It would appear that perhaps there might be a longer ability to sustain at Neptune than I otherwise thought given that you are 50 a day and one well still remains to be drilled. Dave Roberts, any thoughts how long you stay at that level?

Well, Mark, I wish I could predict those kind of things. I will tell you that just talking about Alvheim first. We basically are on the cusp of reaching the facility capacity with seven wells. And as you know, we have more wells existing in the Alvheim complex. We have [Bolen] scheduled to come on next year. So without predicting what the reservoirs are going to do because it's very early days, I think we are on track to basically keep the FPSO plateau level for the foreseeable future.

Neptune again we've got five wells on; the six well will be on in the early part of August. Those wells have performed to expectation perhaps exceeded. But again, very early days, and we will have to let the reservoir shakedown before we make any predictions about how long we can stay at 50 KPD.

Okay, Dave, if I could just follow-up. I was probably doing some rough math on the Bakken numbers that you were talking about and some of those were in the release. How many producing wells do you have currently? I was guessing about being 60. Is that right?

Hold on a second, Mark. I have about 50 wells right now.

That is a guess low or average per well deliverability than I think we have talked about in the past. Is that something that you are seeing?

No. I think we're still in the province of 250 to 300 barrel a day IPs, 30 day average IPs, that's how Marathon measures them, and we still believe that we are talking about 340,000 barrel a day recovery. A lot of what is going on in the Bakken goes how the wells are staggered when they come on. So you have to be very careful how you add up production. But we are not seeing any declamation of what our expectations are.

What's the royalty on that, Dave?

It varies but we have a very high NRI out there.

Okay. Thanks.

All right, we'll move to a question from [George Williams] with JP Morgan.

Hi. Good afternoon. Assuming you all proceed with the separation of the businesses, do you intend to maintain your credit rating at a current level or accept a slightly lower rating?

As I think Clarence already said, we would anticipate setting up both of these companies to be very sound financially, and we expect both of us to maintain an investment grade rating.

Low investment grade, triple B minus level or mid --

I think I answered your question the best I can at this time.

Okay. Thank you.

All right, we'll move forward to a question from [Matt Daley] with Routers.

Thank you for allowing us to join the call today. My question is, of course, on the potential split. First of all I want to look strategically how you're going to assess potentially taking these units apart when refineries are a lot of people believe near the bottom of the cycle at this point. Can you explain how that might affect your judgment?

I'm sorry how it would affect our judgment? Again, we have not made any judgment here. I think what we've said is we are undertaking an evaluation and all of the factors in terms of what the current market is and our projected performance for all of our assets will be taken into account. But again, I don't want to get into a discussion of what the various decision gates are for this evaluation.

Okay. And one follow-up. You did say that we can expect some announcements on the asset disposition in the third quarter. Can you say how that program will be affected by your plan to assess the split off?

Again, the potential separation is in evaluation. So I think the business plans and the actions that we have underway today including all of our operating activities and investment activities as well as the asset sale process that's underway are going to go forward concurrent with the evaluation. So essentially there is no effect.

Okay. Thank you.

Okay, we will take a question from [Jessica Resnick] with Dow Jones.

Hi, this is Jessica [Resnical] with Dow Jones. I do have to go back to the potential separation issue. And I guess one of the things that's interesting to me is that Marathon acquired these assets in a fairly beneficial time for the company in terms of acquiring them right before the boom scene in 2006 and '07. Is the option to do a split being put on the table now because of a sale of these assets is not an option given current asset values?

Again, Jessica, I don't want to comment on how we got to this point or what we think the outcome is going to be. I think you have to accept our announcement at face value. We're undertaking this evaluation, and we intend to conclude it by the fourth quarter of this year. That's about all I will say.

So the evaluation is not considering a sale. It's only considering a separation of the two companies?

That's what our press release says, yes.

Thank you.

Our next question comes from Robin Levine with JP Morgan.

My question has been answered already. Thank you.

Thank you.

We will move toward to a question from Paul Sankay with Deutsche Bank.

Very quickly, guys, is the separation technically a change of control?

It is not.

Thanks, that's it.

All right, and we'll take a question with Mark Gilman with the Benchmark Company.

Guys, at the risk of getting buried in something conceptually that I don't understand, maybe Gary Peiffer or Gary Heminger can help me understand something. You indicated that you have and will continue to hedge long haul crews. Yet, particularly in periods like this, and frankly, in most quarters, we continue to talk about the crude on the water adjustment which, of course, in this period was a particularly significant negative item. If you had been hedging the delivery delay and so far as the crude on the water, why is this crude on the water adjustment even relevant?

Mark, this is Gary Peiffer. The way the crude oil adjustment that we were referring to in Howard's remarks, that's where some of our term purchase crudes, which essentially, we take title to in the Middle East, but we don't actually price until they arrive in the United States by contract. So essentially, contractually those long haul crews on a term basis are at least from a contractual standpoint hedged. We take title but we don't price it until they come to the United States. So that's why we have to provisionally price them when we take title, but we have to reprice them essentially mark to market those crudes until we take delivery. So when Howard referred to the long haul crudes, maybe we didn't make it clear. We were talking about long haul spot purchases. Those crudes we buy on a spot basis that take a long time from the time we contract to buy them to we actually are able to use them.

So two different types of transactions. Term transactions versus spot transactions.

Gary, thanks a lot. If I could have Dave Roberts to clarify the numbers that you put Dave on the plant turnaround deal and facility. I must have gotten something wrong because I think you said 30,000 a day equivalent hit and then you went on to say it was ten for the quarter and it's a 16 day turn. What have I got wrong?

Well, I think the issue is that it's not a complete 16 day shut down mark and what you basically would have seen is we had it planned for a certain number of days to be off 100% and a certain number days of warm up and what I mentioned to you is that we are well ahead of the 16 day schedule in terms of starting on the 19th. Basically back in full capacity by this weekend and basically brought the plan up to 50% by the beginning of this week, and so it's probably just the number of days in your calculation.

Less than 60 days and the number should be a lot smaller.

16 -- 16, 1-6.

We'll take it offline. Thanks.

And we have no further questions remaining at this time. I would like too turn the conference back over to Mr. Thill for any additional or closing remarks.

We appreciate all of the interest from those listeners, and we hope you have a good afternoon. Good-bye.

Thank you so much, sir. This does conclude today's teleconference. Thank you for your participation. Have a great day.