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Executives

Howard J. Thill - VP, IR and Public Affairs

Steven B. Hinchman - Sr. VP, Worldwide Production

Clarence P. Cazalot, Jr. - President and CEO

Janet F. Clark - EVP and CFO

Gary R. Heminger - EVP

Philip G. Behrman - Sr. VP, Worldwide Exploration

Garry L. Peiffer - Sr. VP, Finance and Commercial Services

Analysts

Robert Kessler - Simmons & Company

Mark Flannery - Credit Suisse

Neil McMahon - Sanford C. Bernstein

Arjun Murti - Goldman Sachs

Nicole Decker - Bear Stearns

Paul Sankey - Deutsche Bank

Doug Leggate - Citigroup

Paul Cheng - Lehman Brothers

Mark Gilman - The Benchmark Company

Doug Terreson - Morgan Stanley

Marathon Oil Corporation (MRO) Q4 FY07 Earnings Call January 31, 2008 2:00 PM ET

Operator

Good day, and welcome to Marathon Oil's Fourth Quarter and Full 2007 Year’s 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.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Thanks, Allan. As Allan said, welcome to Marathon's fourth quarter 2007 earnings webcast and teleconference. You can find the synchronized slides that accompany this call on our website, marathon.com.

On the call today are Clarence Cazalot, President and CEO; Janet Clark, Executive Vice President and CFO; Gary Heminger, Marathon Executive Vice President and President of our Refining, Marketing and Transportation Organization; Phil Behrman, Senior Vice President, Worldwide Exploration; Steve Hinchman, Senior Vice President, Worldwide Production; Dave Roberts, Senior Vice President, Business Development; and Garry Peiffer, Senior Vice President of Finance and Commercial Services Downstream.

Slide 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. In accordance with Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its Annual Report on Form 10-K for the year ended December 31, 2006 and subsequent Forms 8-K and 10-Q cautionary language identifying the important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

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 and 2007. As shown on slide four, adjusted net income for 2007 decreased 19% from the 2006 level to $3.8 billion, while the fourth quarter 2007 was down 40% compared to the same quarter of 2006. As shown on slide five, on a diluted per share basis, adjusted net income for 2007 was down 15% from 2006 compared to the decrease of 19% just discussed, reflecting the lower average diluted share count outstanding during 2007 due to our share repurchase program. The fourth quarter adjusted net income per diluted share was down 41% from the fourth quarter of 2006, reflecting the somewhat higher average share count for that period due to the Western Oil Sands acquisition completed October 18, 2007. We recommenced our share repurchase program late in the fourth quarter following the close of the Western transaction and made minimal repurchases during that period.

Moving to slide six, the year-over-year decrease in adjusted net income was largely the result of a lower refining in wholesale marketing gross margin and lower upstream sales volumes, partially offset by lower income taxes. As shown on slide seven, the year-over-year decrease in fourth quarter adjusted net income was largely a result of a lower refining and wholesale marketing gross margin, partially offset by higher liquid hydrocarbon realizations in our upstream segment and lower income taxes.

Fourth quarter 2007 results were also negatively impacted by higher exploration expense, which was primarily related to expensing non-commercial well on the Flathead prospect in the Gulf of Mexico and a loss in our Oil Sands Mining segment. The Oil Sands Mining segment reflects results since October 18, 2007, which as I mentioned earlier was the closing date for the transaction. This new segment reported a loss of $63 million for the quarter, including a $39 million after-tax unrealized loss on crude oil derivative instruments held by Western at the date of acquisition. Segment income was also impacted by a mid-November fire and subsequent curtailment of operations at the Scotford Upgrader during the fourth quarter. The Upgrader returned to operation in late December.

Slide eight compares adjusted net income for the fourth quarter of 2007 to the third quarter of 2007 and shows the decrease was primarily a result of a lower refining and wholesale marketing gross margin, as well as the previously mentioned higher exploration expense in Oil Sands Mining segment loss, partially offset by higher upstream liquid hydrocarbon and natural gas realizations and lower taxes.

Turning to slide nine, the $274 million decrease in the upstream segment income for 2007 compared to 2006 was primarily a result of lower liquid hydrocarbon sales volumes and higher exploration expense, partially offset by lower income taxes and higher realizations. As detailed on slide ten, upstream segment incomes for the fourth quarter decreased $14 million from the third quarter of 2007. The quarter-over-quarter performance was negatively impacted by higher income taxes due to a higher percentage of income from international locations and the higher exploration expense previously mentioned, and positively impacted by higher liquid hydrocarbon and natural gas realizations.

As shown on slide 11, worldwide sales volumes decreased 17,000 barrels of oil equivalent or BoE per day in the fourth quarter of 2007 as compared to the third quarter of 2007, largely a result of downtime at Equatorial Guinea LNG facility due to warranty work. Also, the average realized price per BoE increased $10.35 from the third quarter of 2007 to the fourth quarter of 2007.

Moving to slide 12, domestic upstream income for the full-year of 2007 decreased $250 million from the year 2006, largely as a result of lower sales volumes and the higher exploration expense, partially offset by higher liquid hydrocarbon realizations and lower income taxes.

Moving to slide 13, while domestic upstream income for the fourth quarter was up only slightly from the third quarter, there were two large swings from the previous quarter with higher sales price realizations essentially offset by the higher exploration expense. As shown on slide 14, the NYMEX prompt price for WTI crude was up $15.35 per barrel from the third quarter, while our average domestic realized liquid hydrocarbon price was up $10.63. Our lower realizations compared to the NYMEX were primarily the result of weaker differentials for Gulf Coast sour and Wyoming asphaltic crudes. The Bid Week natural gas price was up $0.81 per million BTUs from the third quarter, while our domestic natural gas realizations were up $0.56 per million cubic foot or Mcf. Our Lower 48 realizations were up $0.61 per Mcf.

Turning to slide 15, fourth-quarter domestic upstream expense excluding exploration expense were $0.71 per BoE lower than the third quarter, while domestic upstream income per BoE increased $0.63 quarter-over-quarter.

On slide 16, you will see that international upstream income for 2007 was essentially flat compared to 2006, with lower liquid hydrocarbon sales volumes being mostly offset by lower income taxes and lower exploration expense. Slide 17 shows international upstream income for the fourth quarter decreased slightly compared to the third quarter, as lower liquid hydrocarbon and natural gas sales volumes and higher income taxes were offset by higher realized prices. As shown on slide 18, our international liquids realizations increased $14.27 per barrel, basically in line with Dated Brent, which increased $13.70 per barrel. International natural gas realization increased $1.58 per MCF compared to the third quarter, largely as a result of seasonally higher spot natural gas prices in Europe and lower gas volumes... gas sales to our LNG facility in Equatorial Guinea due to the plant shutdown from early October to mid-November. Please remember that our L&G business is reported as an Integrated Gas segment. So there is additional uplift in value realized by the EG LNG facility that is not reported through our upstream business.

Turning to slide 19, fourth quarter International upstream expense excluding exploration expense increased $2.34 per BOE over the third quarter of 2007, largely a result of lower production and higher operating costs, while total income per BOE increased $0.11 to $15.76 primarily due to the higher realizations. Slide 20 shows our upstream reserve replacement for the past four years including the rolling three-year averages. The proved bitumen reserves associated with the Athabasca Oil Sands project are not included in these numbers.

I will now turn the call over to Steve Hinchman to provide more details around our 2007 reserve replacement as well as our 2008 production and cost forecasts for the upstream segment.

Steven B. Hinchman - Senior Vice President, Worldwide Production

Thank you, Howard. In 2007, Marathon added 88 million barrels of oil equivalent of net proven liquid hydrocarbon and natural gas reserves while producing 125 million barrels of oil equivalent, resulting in a reserve replacement ratio of 70%. Reserve additions consist of 37 million barrels of oil equivalent in the US and 51 million internationally, in both areas about equally split between liquid hydrocarbon and natural gas. The additions are primary a results of drill bit activity, including onshore US, Alvheim/Vilje development drilling, and infill drilling activity in Libya. At the end of 2007, our total proven reserves are 1.225 billion barrels of oil equivalent. 879 million or 72% are proved and developed. This compares to a total proven reserve of 1.262 billion barrels of oil equivalent at the end of 2006, of which 68% was prove and developed.

Over the three-year period ending in 2007, Marathon’s average reserve replacement ratio excluding disposition is 135%. The lower replacement ratio in 2007 reflects a year in which we did not sanction any new major development projects. Our reserve replacement expectations on a rolling average basis remain greater than 100%. The costs incurred will be available in mid-February. So any discussion of finding and development costs will need to be deferred until then.

Our production guidance for 2008 is 380,000 to 420,000 barrels of oil equivalent per day. This falls short of the guidance given in November of 2006, which was 450,000 to 480,000. This shortfall is not due to our base production, which has consistently performed within expectation, but is caused by delays in production startup of development projects. The most significant of the delays in the Alvheim and Vilje projects in Norway and the Neptune project in the Gulf of Mexico.

In November 2006 guidance, the Alvheim and Vilje projects were to start production in the first quarter of 2007. We now expect startup at the end of the first quarter of 2008. The initial expectation would have resolved it in nearly a full-year production in 2000 at FPSO capacity. Now, we have both the delay startup and the production ramp-up [inaudible] wells in and optimize the operation, all occurring in 2008. We expect to move the FPSO out of Haugesund in mid-February. We’ll need to start Ammanford where we can install the thrustors and do some additional commissioning that also requires deeper water. We expect this will take about ten days and then will sail to the field. The biggest threat at this time is having the necessary weather window as we move and position the vessel.

In the 2006 guidance, the Neptune project in the Gulf of Mexico would start production at the beginning of 2008. The operator now expects that first production will occur at the end of the first quarter. The timing of delivery of major projects has proved difficult in today's volatile environment. These large projects have missed by even a few months and have a significant impact on our quarterly and annual production estimates. But we remain confident that our growth guidance from 2006 to 2010 of 9% is achievable.

Now turning to cost guidance, the 2007 operating cost, excluding FAS 144 impairment, production tax, foreign royalty and exploration fall within the guidance provided. For 2008, we expect operating cost on a similar basis for the US to range between $23.50 to $26 per barrel of oil equivalent, and for international between $16 and $18.25 per barrel of oil equivalent. I'll now turn it back over to Howard.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Thanks, Steve. We appreciate that update. Moving to our downstream businesses in slide 21, full year 2007 segment income totaled $2.1 billion compared to $2.8 billion in 2006. This decrease was largely a result of the challenging refining and wholesale marketing gross margins in the last two quarters of 2007, which lowered our annual average margin $0.044 per gallon year-over-year.

Turning to slide 22, downstream fourth quarter 2007 segment income totaled $4 million comment to $533 million earned in the same quarter of 2006. Because of the seasonality of the business of the downstream business, I'll compare our fourth quarter results against the same quarter for 2006. The average LLS 6-3-2-1 crack spread for the quarter on a two-third Chicago and one-third US Gulf Coast basis was weaker in the fourth quarter of 2007 compared to the fourth quarter of 2006, decreasing 25% from $3.19 per barrel to $2.39 per barrel. The most significant factor contributing to the downstream segment's results quarter-to-quarter was that the company's average wholesale sales price realizations in the fourth quarter 2007 did not increase over the comparable prior-year period as much as the average spot market prices viewed in LLS 6-3-2-1 calculation. The most significant difference was the average price of all the products we sell other than gasoline and distillate only increased about $0.28 per gallon from the fourth quarter of 2006 to fourth quarter of 2007, whereas the average 3% residual fuel oil price used in the 6-3-2-1 calculation increased almost $0.67 per gallon on average quarter-to-quarter.

In addition, our crude oil cost increased substantially more than the quarter-to-quarter change in the average price of LLS would indicate. The primary reason for this increase was that the market structure for crude oil changed from a contango market, which averaged about $1.83 per barrel in the fourth quarter of 2006, to a backwardated market in the fourth quarter 2007, which averaged about $1.37 per barrel. The change in the market structure substantially increased our acquisition cost for crude oil compared to the change in LLS prices quarter-to-quarter. We also incurred a loss of $42 million on our foreign crude oil and transit inventory in the fourth quarter of 2007 versus a gain of about $14 million in the same quarter of 2006 due to the change from falling crude oil prices in the fourth quarter of 2006 compared to the rising crude oil prices in the fourth quarter of 2007. We also incurred substantially higher operating and administrative costs in the fourth quarter of 2007, primarily due to higher planned turnaround expense in other maintenance and salaries.

Marathon’s refining and wholesale marketing gross margin includes pretax derivative losses of $427 million for the fourth quarter and $899 million for the full-year compared to pretax derivative gains of $194 million and $400 million in the same periods of 2006. The derivative changes reflect both the realized the effects of close derivative position as well as unrealized effects as a result of marking open derivative positions to market. Most of our derivatives have an underlying physical commodity transaction. However, the income effect related to our derivatives and the income effect of our underlying physical transaction may not necessarily be recognized in net income in the same period. Partially offsetting these negative results was a positive impact from our ethanol blending the program due to the relatively lower ethanol prices compared to gasoline prices during the fourth quarter of 2007 versus the prior year quarter.

We completed major turnarounds in the fourth quarter at our Catlettsburg, Robinson, and St. Paul Park refineries, primarily involving our fluid catalytic cracking units at all three plants. Therefore, while crude oil inputs improved from the fourth quarter 2006, our average crude and other blend stock inputs were down about 3% for the fourth quarter 2007 compared to the same quarter of 2006. This was also the primary reason our 2007 fourth quarter gasoline production was down about 7% from the prior year’s quarter. We did however have record crude oil and total throughputs for the year 2007.

Moving to slide 23, Speedway SuperAmerica or SSA had gasoline and distillate sales for the fourth quarter of 2007, which were down 6 million gallons or a decrease of 0.7% from the fourth quarter of 2006. SSA same-store gasoline sales volumes were down 1.3%, and same-store merchandise sales increased 1.1% in the fourth quarter of 2007 compared to the fourth quarter 2006. SSA’s gross margin for gasoline and distillate sales was essentially unchanged between the two quarters.

Slide 24 provides a summary of segment data along with reconciliation to net income. Slide 25 provides selective preliminary balance sheet and cash flow data. Cash adjusted dept to total capital at the end of the fourth quarter was approximately 22%. And as a reminder, this cash adjust debt balance includes just under $500 million of debt serviced by US Steel. 2007 preliminary cash flow from operations was approximately $6.5 billion and preliminary cash flow from operations before working capital changes was approximately $5.6 billion. Slide 26 provides selected financial and operating results for 2006 and 2007, while slide 27 provides guidance for the first quarter and full-year 2008, some of which Steve just discussed.

I will now turn the call over to Clarence Cazalot, Marathon's President and CEO.

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

Thank you, Howard, and good afternoon everyone. It is pretty clear that the fourth quarter was a difficult one for Marathon, primarily because of the impact rising crude oil and feedstock cost had on downstream margins. We also had a higher than expected exploration expense and unscheduled downtime, both at EG LNG and in the Athabasca Oil Sands project. We are not satisfied with that performance, especially as to those areas we can control. But taken in its entirety, 2007 was a solid performance year for the company and we advanced our growth plans across the corporation.

For 2008, we expect substantial growth in our oil and gas production volumes, the sanction of at least two major upstream developments, further progress on the large refinery projects at Garyville and Detroit, and a full year of operations both in EG LNG and in our Oil Sands business. These significant growth plans were incorporated in the $8 billion capital and exploratory expense budget we announced yesterday.

I'd like to ask Janet Clark to provide you a comparison of that budget to the guidance we gave in November of 2006 of $5.2 billion.

Janet F. Clark - Executive Vice President and Chief Financial Officer

Most of the $2.8 billion increase represents new investment opportunities rather than the cost inflation. In fact, the majority is related to currently new projects. Our Canadian Oil Sands asset, we’ll be investing $900 million in 2008. The Detroit Heavy Oil Upgrade project, which our Board sanctioned last year, we’ll have a about a $700 million increase.

As you know, we are the successful bidder in the Gulf of Mexico lease sale in last fall. About a $155 million will be awarded… we expect to be awarded in 2008 and will be part of our 2008 capital budget. I am sure you are aware of the significant Droshky discovery that we made last year. We have got about $250 million of development capital in the budget for that project. In addition, we have accelerated the spending on the Garyville major expansion project by about $200 million in 2008. I would point out that we are still on track for the $3.2 billion overall project.

In addition, we have about a $100 million of incremental capital in 2008 for midstream infrastructure to support our refining operations. We have got an incremental $125 million for Angola appraisal and development. So there remains about $300 million for increased spending in some smaller E&P projects and some cost escalation. In addition, because of the higher level of activity, our capitalized interest would be up about $120 million for the year.

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

Thank you, Janet. I would simply point out that… you'll note that in these increases we have both the new projects we didn't have in the plan in November of '06 as well as the fact that these are… several of these investments are in very long life projects such as the refinery projects and in Oil Sands.

And I think in light of that higher level of spending it will be appropriate for Janet to comment on the financial flexibility and wherewithal that we have to carry this out.

Janet F. Clark - Executive Vice President and Chief Financial Officer

As we have always talked about, our financial philosophy is to remain very disciplined and maintain financial flexibility. We have commenced the review of our portfolio of assets with the intent of monetizing those assets, which are either mature or otherwise non-strategic in order to redeploy our capital from those assets into the growth projects that I just mentioned. We are in the early stage of this exercise. So I would say that any proceeds from these sales… or the potential sales would be weighted towards the second half of the year.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Thanks, Clarence. Thanks, Janet. Before I open the call up to questions, I'd like to remind everyone that to accommodate all the questions, we would ask you to limit yourself to one question plus a follow-up. You're welcome re-prompt for additional questions as time permits. For the benefit of all of the listeners, we ask you to identify yourself and your affiliation. And with that Allan, if you would open up to questions, we would appreciate it.

Question and Answer

Operator

Thank you. [Operator Instructions]. We will begin with Robert Kessler from Simmons & Company.

Robert Kessler - Simmons & Company

Good afternoon, a question with respect to your CapEx program, $8 billion is quite a healthy number and I do appreciate that you plan on divesting some assets later in the year to help meet that organic funding requirement. But can you speak to the ability to meet in the mean time the CapEx funding in the early part of the year with cash flows from operations, and to what extent you might look to debt level grow a little bit throughout the course of the year and also, whether or not you might pull back a bit of buy backs until you saw some assets?

Janet F. Clark - Executive Vice President and Chief Financial Officer

That's the one question I guess with a lot of parts to it. As we look at the plan going forward… I think we ended the year right at around 20% net debt to capital, which is still a very, very comfortable level. So the asset optimization is really a part of just putting business in terms of trying to have our capital invested in those projects so we can create the most value for the shareholders, but at the same time it will be creating greater flexibility.

In terms of our ability to fund the CapEx program with cash flow from operations, that really depends on where commodity prices are, where crack spreads are, and that's very difficult to forecast. But certainly, there are scenarios where we would be accessing the fixed income capital market to fund the program in the first half of the year.

With regard to the stock buyback program, as you know, we are very committed to probably shareholder return, and we did recommence the share buyback program in the fourth quarter. I think we've said before that we don't expect that… to execute on that program as ratably as we have in the past. It really will be influenced more by cash flow from operations as well as asset sale proceeds. However, it remains our intent to complete the 2.5 billion of remaining authorization by the end of 2009.

Robert Kessler - Simmons & Company

Okay. Thanks, Janet.

Operator

[Operator Instructions]. And we will take our next question from Mark Flannery from Credit Suisse.

Mark Flannery - Credit Suisse

Hi. I have fairly a simple question about the Oil Sands expenditure, particularly with regard to AOSP, which I guess is most of it. The $900 and so million number that you're talking about now as incremental to the November budget, is that number the same number you thought it would be as... when you were buying Western Oil Sands? In other words, has there been a budget increase at AOSP between completing the transaction and talking about CapEx last night?

Gary R. Heminger - Executive Vice President

Mark, this is Gary. And looking at that budget when we put this acquisition together, just some very minor timing changes, but it is still based off the same base number that we would have anticipated when we put the evaluation together.

Mark Flannery - Credit Suisse

Right. Okay. Maybe I'll have a sneaky follow-up on Garyville. What have you brought forward for Garyville, what's the extra $200 million for?

Gary R. Heminger - Executive Vice President

We are not following a word [ph] here, Mark. We are running a little bit ahead of schedule on the commitments of the major compressors and big vessels, so they are... we expect them to arrive a little early. We have committed now almost 100% of all of the equipment that is anticipated. And again, I don't want to jinx our project team, but they are just run a little bit ahead of schedule on the site work. So it's just bringing forward… as we put this budget together over two years ago now and had our charts and progress planning. We're just a little bit of ahead of where we had anticipated to be at the time.

Mark Flannery - Credit Suisse

Right. Okay. Thank you very much.

Operator

And next we'll hear from Neil McMahon from Sanford Bernstein.

Neil McMahon - Sanford C. Bernstein

Hi, I've got a few questions about the reserves. First of all, just looking at onshore U.S., Steve, I think you said 37 million was what you booked in the year for new additions at the drill bit. I was just wondering what was the flexibility around that, given the fact that we had an end-year price of over $90? Did that influence the booking at all?

And then, maybe a question for Phil, just to go into the resources that you’d feel in Angola and in other places that are yet to be booked under pre-FID? Thanks?

Steven B. Hinchman - Senior Vice President, Worldwide Production

Yes, Neil, this is Steve Hinchman, and there was no pricing really impact on the reserve adds. The 37 million in U.S. was all really just drill bit performance, no real price impact whatsoever.

Philip G. Behrman - Senior Vice President, Worldwide Exploration

Neil, in regards to Angola resources, I think in the spring we'll have an analyst meeting. We'll be able to give you an update of the resources we have discovered. That being said, we currently have a rig running on Block 31 as well as a rig running on Block 32 currently drilling appraisal wells.

Neil McMahon - Sanford C. Bernstein

And you're still talking about FID or thinking about FID in 2008 for Angola?

Steven B. Hinchman - Senior Vice President, Worldwide Production

Neil, this is Steve Hinchman. Yes, we would expect that development in Block 31 would come to sanction in the first quarter of 2008.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

I would say, Neil, and to that point of the first sanction of 31 northeast, if you look at most of Phil's exploration success, one of the few areas we've actually booked reserves thus far is at Alvheim/Vilje, obviously with the sanction of that project. None of the Angola success nor Droshky, our 2007 discovery in the Gulf of Mexico, at this point has been booked. It'd be primarily on Alvheim/Vilje and Neptune would be where we have booked reserves associated with the exploration success we got.

Neil McMahon - Sanford C. Bernstein

Okay, great. Thank you.

Operator

And next, we will hear from Arjun Murti from Goldman Sachs.

Arjun Murti - Goldman Sachs

Thank you. Just a follow-up on some of the downstream spending, even with the $200 million acceleration Garyville it still seems like a decent size number. How much in total are you spending at Garyville this year, and what contribution was the Detroit coker to the '08 numbers? And then related, what kind of a follow-on CapEx in '09 and '10 can we expect in the downstream? Thank you.

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

Okay, Arjun. Just give me a second here. I can… we are getting all the capital here over the next couple of years, but your second question on what type of response will we get from the Detroit in this year, we won't expect any of the coker, any of that benefit to really come into us until 2010 to 2011.

Arjun Murti - Goldman Sachs

I apologize, guys, I meant the CapEx contribution for '08 for Detroit coker.

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

I'm sorry.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Well, Garry Peiffer here has all the individual numbers. Let him go over them with you.

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

Garyville, we will expect to spend about $1.7 billion there this year. Detroit is going to be in the 600... excuse me, Detroit will be actually a little bit more when you consider the pipeline activity.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

About 700.

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

Yes, about 700 million there in Detroit. So, 1.7, 1.8 in Garyville and about 700 million or so at Detroit.

Arjun Murti - Goldman Sachs

Got you. That will get me there. If I can just ask one related to refining, what was the unrealized loss for fourth quarter, not the realized but the unrealized derivative loss?

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

Well, one minute. Maybe we can get back to you on that, Arjun. I'm still looking up here.

Arjun Murti - Goldman Sachs

No problem. Thank you very much.

Operator

[Operator Instructions]. And next, we will hear from Nikki Decker from Bear Stearns.

Nicole Decker - Bear Stearns

Good afternoon. My question is on the derivative instruments at Western Oil. Would you just talk about what happened during the quarter and how you think these instruments might affect future performance and whether there is any flexibility?

Gary R. Heminger - Executive Vice President

Yes, Nikki. This is Gary. When the Western had put these instruments on prior to us completing the transaction, but of course we were aware that these instruments were on and they were on and it all indented to mitigate the price risk related to that future crude. And what they have on a yearly basis, they have about 20,000 puts and 15,000 calls for 2008 at a collar of $50 floor, $90 ceiling. And in 2009, they have 20,000 puts and 15,000 calls as well at the same floor and ceiling. And to say is there anything we can do it to mitigate that, you look at the collar and I guess yes, what it does here is of course an opportunity loss that we had last year. We are aware that it is going in, but at this time we do not see any way to anything that economically would justify buying our way out of that position.

Janet F. Clark - Executive Vice President and Chief Financial Officer

And of course, Nikki, when you have a cost with collar you have the mark-to-market both components of it. And to the extent that the price stays within that collar, we wouldn’t necessarily... ultimately, we have any task. So if prices stay where they are you could see that reversal as those hedges mature.

Nicole Decker - Bear Stearns

Thank you.

Operator

And next, we’ll hear from Paul Sankey from Deutsche Bank.

Paul Sankey - Deutsche Bank

Hi, everyone. Just following up on the hedging question, could you on an overall corporate level just go through any changes that are occurring to your hedges… hedging position in the course of '08 as opposed to '07 to the extent that you can? Thanks.

Janet F. Clark - Executive Vice President and Chief Financial Officer

I'll answer that, Paul, from the upstream. We continued to not put on equity hedges, either on natural gas or on oil, and Garry, you want to take the downstream.

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

Sure, Janet. Paul, I think… you are well aware there has always been kind of our acquisition… feedstock acquisition strategy to try to price our feedstocks as close we can to when we use them to produce the products, and we are not changing that strategy. We are continuing to looking at it and evaluating it, but it's always been our strategy to try to create value based upon refining margins and to minimize the price risk that we have from the time we lock in the price of the feedstocks until we sell the refined products. So it's a continuous process that we are looking at it, but at this time we have no major changes in strategy that we've decided on at this time.

Paul Sankey - Deutsche Bank

I’ve got the impression, perhaps I misheard, that thee were some hedges that rolled off during the course of '07 and you'd been there somewhat less hedged in '08 than you were in '07?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

No.

Paul Sankey - Deutsche Bank

Okay, maybe not, I must be mistaken. If I was just trying to get to the underlying performance of the Scotford, do you have an idea of what, if you like, opportunity cost of the problems there were in Q4 so that we can get an idea of what you typically might make of that asset if we were at a more lower level of operation?

Steven B. Hinchman - Senior Vice President, Worldwide Production

Well, I will answer it this way, Paul. We were down… I believe it was November 15 or so is when we were down. We believe… and we were up to that time averaging around 30,000 barrels per day net to us, but then of course we had all of the expense to go in and fix this problem, first of all emergency response and then maintenance repair, to go in and fix this problem. Not only in Conversion unit one, but in conversion unit two to ensure it doesn't happen in the second conversion unit.

And I will have to get back with you Paul on the detailed expense over that period of time, but as I said we were running at around 30,000 barrels per day and expect as Howard mentioned in his discussion that that should continue to be our approximate run rate here going forward into 2008. Now, I'll have to get back to you with the detailed expense. You’ll realize they haven't... they are still finalizing all the billings and everything, so all of that isn't in here, Paul, for December.

Paul Sankey - Deutsche Bank

I’ve got you.

Operator

And next, we will take Doug Leggate from Citi.

Doug Leggate - Citigroup

Hi. Good afternoon, everybody. My question I guess is on Janet's comments regarding disposals. Can you give us some idea… I am sure you've probably got a reasonable idea of what might make it into the program, sort of magnitude you would anticipate in terms of the size of the disposal program, what are the focus in terms of what assets upstream or downstream might be targeted.

And I guess specifically, we all know you got some fairly long-dated I guess reserve potential in Angola. Does some or part of the Angola position make it into that disposal program and in… some time in the future?

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

Doug, this is Clarence. I guess I would say that there is no specific focus upstream or downstream. It is a review of our entire portfolio of assets. We don't have a specific target level. We will target those assets that we think can garner greater value in the market than they do to our… in our internal portfolio. But I would just clarify for everyone that this isn't something we necessarily need to do to fund our program. It's something that we think is part of solid good businesses, as Janet has indicated. So to a certain extent, in the marketplace we see today if we can get the kind of value we think is solid, we will move, if we don't then we wont' sell. So it is a discretionary process with respect to whether or not Angola… any of the Angola blocks is in the process, Doug. It’s premature for us to say. As I've said, all assets are being looked at.

Doug Leggate - Citigroup

All right. Thanks, Clarence.

Operator

And next we'll hear from Paul Cheng from Lehman brothers.

Paul Cheng - Lehman Brothers

Hi, guys. I think that the first one you said, Howard, when you finally did the cost for the [inaudible], can you also give me a cost?

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Sure, we can do that Paul.

Paul Cheng - Lehman Brothers

Yes, that would be great. I guess my question is to Garry. I understand in the past that why you while to do the [inaudible] acquisition, but when you're looking at that I mean, does it really accomplish anything? I mean, over the long haul in a backwardation market or in a contango market that you have a reverse impact, and so over the long haul that is a net zero in terms of value, but there's a cost associated with managing that kind of a of program. So it ends up there to be a net loss all the time. You're just creating more volatility in your earnings comparing to what the other are people looking at. So I'm not sure that is it really for the benefit of the company. When you’re a far smaller company or the industry in more difficult time and constantly worry about cash flow, maybe the bank require it, but I can't imagine the bank require you guys to do something like that today. So maybe that you can help me to understand a little bit better why you insist to continue doing in that way?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

This is Garry Peiffer. And I think you understand obviously how it is calculated and you’ve fit all the attributes there and then… at least historically, our preference to minimize that risk for how many of our days we had to lock in the price. But as the market, Philip, last year from a contango market into a backwardated markets, obviously we have to rethink, is that right strategy going forward. I guess the big question becomes, at $90 crude prices how do you… if you were to change it when would you change that change that strategy because to a certain degree we've obviously paid the price going up this level.

Paul Cheng - Lehman Brothers

And more importantly is that… I mean in anyway that you don't hedge your product side of your selling price, so why even bother then to hedge… I mean if two side of the equation, right, in order to get a cash flow just, what is crude cost and what is the product price you're selling? If you don't hedge, the product price why you want to hedge the crude cost?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

Well, the product price is really the big unknown that we are trying to bring the crude price into sync with what is going on in the market on that day.

Paul Cheng - Lehman Brothers

I understand that, Garry, but what I'm saying to you is that is it’s still not going to give you the net result that… to have a non-debt cash flow or margin in anyway because you don't know what is one end of the pricing going to be?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

That's correct, and as you will know we were just... our strategy is to try and bring that crude price determination or price into sync with the market on the day we sell the product. So that's been our strategy to try make it on the margin rather than on the price change.

Gary R. Heminger - Executive Vice President

And Paul, this is Gary. We take your point. We understand it. We've had a number of discussions over the years on this strategy. The way you run the arithmetic is correct and we continually look at this strategy. As Garry said, question you have, you pay the tuition up into the $90 to $100 range and that's where we are. But we will continue to look at this and review this with our executive management before we make a decision to change.

Paul Cheng - Lehman Brothers

Gary, can I sneak in one short question?

Gary R. Heminger - Executive Vice President

Sure.

Paul Cheng - Lehman Brothers

What is the [inaudible] sales volume on those best tuck stop over 12 months?

Gary R. Heminger - Executive Vice President

Just on the distal side, Paul.

Paul Cheng - Lehman Brothers

Yes, sir. Thank you.

Gary R. Heminger - Executive Vice President

That's the most meaningful number. It was around 4% on a same-store basis, quarter-over-quarter.

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

4.3% to be exact, but 4.3% year-over-year increase.

Paul Cheng - Lehman Brothers

Thank you.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Thanks, Paul.

Operator

Next, we will hear from Mark Gilman from Benchmark.

Mark Gilman - The Benchmark Company

First, good afternoon. Hey, Clarence, I assume that of the two major upstream development projects you referenced in your comments that the northeast section of Block Angola... Block 31 Angola and is one of them, what's the other one?

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

The other one is the Droshky discovery in the Gulf of Mexico, Mark.

Mark Gilman - The Benchmark Company

So contingent upon the appraisal well you’re drilling?

Clarence P. Cazalot, Jr. - President and Chief Executive Officer

Yes.

Mark Gilman - The Benchmark Company

Okay. My unrelated follow-up because it goes back to the downstream number. I know that you like to look at the comparison versus the year ago in which case the backwardation versus contango structure is relevant. However, if you look at versus the prior quarter where if anything, the market was probably to my recollection a little less backwardated, but not materially different. That really wasn't much of an effect. Yet the earnings impact between the quarters was just way out of line with what the deterioration in the margin environment was. So what I am wondering is, what kind of derivative impact is in there versus these… the immediately prior quarter? And was it the FCC turns or something along those lines that made a major contribution to the deterioration in the gross margin?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

Mark, this is Garry Peiffer. I think the biggest contributor to our fourth quarter 07 to the third quarter '07 is if you look at just the LLS 6-3-2-1 crack, in the third quarter it averaged on a two-third Chicago, one-third Golf Coast basis, about $0.09 a barrel. Fourth quarter on that same two-third, one-third basis was $2.39 a barrel. So we lost about $750 million of value… or profit just because of the market swing from the third to fourth quarter.

To you question on contango, backwardation, in the third quarter we were in contango on average about $0.39 and we were above 33, as Howard said, negative in the fourth quarter. So there was about a $75 million swing right there. As you know, our Delba profit quarter-to-quarter was off about $750 million or so. So the lion’s share of the effects between third and fourth quarter was basically the market had really shrunk on us as well as the change in the structure.

Mark Gilman - The Benchmark Company

Garry, is there anything in the way of mismatched derivatives that burdens the comparison you just talked about?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

No, I don't think so. I think as I said, about $750 million swing, if you just take the change in the crack quarter-to-quarter.

Mark Gilman - The Benchmark Company

Yes, but you get some sweet/sour and light/heavy help on that too?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

There's going to be... there is definitely pluses and minus. No doubt about it.

Mark Gilman - The Benchmark Company

Okay. Thanks, guys.

Operator

And next we'll hear from Ted Disant [ph] from Bear Stearns.

Unidentified Analyst - Bear Stearns

Yes. Good afternoon, everybody. I think this question is only for Janet. I know you talked a little bit about the financial flexibility and I'm wondering, can you give us any guidance as to whether or not you'll come to the debt capital markets this year, and if so how much you might borrow?

Janet F. Clark - Executive Vice President and Chief Financial Officer

Yes. It will be predicated upon predicated upon the timing of cash flows, where commodity prices are, where crack spreads are. I think that given that we've$400 million maturity in March, it would be likely that we'll come sometime in the first half. The amount is going to be really dependent upon what the cash flow from operations are and where we see the asset sale program going?

Unidentified Analyst - Bear Stearns

Okay, thanks.

Operator

And next, we'll hear from Doug Terreson from Morgan Stanley.

Doug Terreson - Morgan Stanley

I think we need only one more derivatives question, so I am going to go ahead and ask it.

Steven B. Hinchman - Senior Vice President, Worldwide Production

Of course.

Doug Terreson - Morgan Stanley

And it really goes back as a clarification to Gary's comments regarding the collars, positions, etcetera. Were those comments related to the derivative losses in Oil Sands operation or the refining and marketing or both? Can you just clarify what those comments related to, and Janet had some comments on it too, I think?

Steven B. Hinchman - Senior Vice President, Worldwide Production

Oil Sands.

Gary R. Heminger - Executive Vice President

Yes, Doug, that was all Oil Sands. The 20,000... excuse me, 20 million barrels of puts and 15 of calls were all Oil Sands.

Doug Terreson - Morgan Stanley

Okay. And the derivative issue with refining and marketing was touched on by Paul earlier. Is that correct?

Garry L. Peiffer - Senior Vice President, Finance and Commercial Services

That's correct. He just talked about market structure.

Doug Terreson - Morgan Stanley

Absolutely. Okay. I just want to be sure. Thanks.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Okay.

Operator

[Operator Instructions]. And next, we'll take our question Mark Gilman from Benchmark.

Mark Gilman - The Benchmark Company

This one's for Janet. Janet, can you give me rough idea on the purchase accounting allocation for Western? What percentage of the PP&E was allocated to producing versus non-producing?

Janet F. Clark - Executive Vice President and Chief Financial Officer

Yes, Mark, I'd love to, and we will be providing that in some detail in the 10-K, which we'll file before the end of February.

Mark Gilman - The Benchmark Company

Okay. Thanks a lot.

Operator

And next, we will hear from Bernard Forne from Valeres Capital [ph].

Unidentified Analyst

Yes, good afternoon. I just wondered if you've talked about any non-Canadian assets, either probable or prospects, so non-Canadian oil reserves for the Western Oil Sands acquisition. I think I recall they had some stuff in the Mid-East. I don’t know if that‘s something that you've discussed or was part of the deal?

Steven B. Hinchman - Senior Vice President, Worldwide Production

It was... they had exploration assets in Kurdistan that was not part of the deal.

Unidentified Analyst

So, they hived that off before you purchased it?

Howard J. Thill - Vice President, Investor Relations and Public Affairs

That's correct.

Steven B. Hinchman - Senior Vice President, Worldwide Production

They took that off, there was a company called Western Zagros.

Unidentified Analyst

Okay. Thanks a lot.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Allan, if there is no more--.

Operator

We do have one follow-up question from Mark Gilman.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Okay.

Mark Gilman - The Benchmark Company

Steve Hinchman, I'm a little bit surprised at the lower level of the backend production in the quarter. Give me an idea how many wells are currently producing and what you're seeing in terms of reserve per well, and whether it meets what your expectations were?

Steven B. Hinchman - Senior Vice President, Worldwide Production

Yes, Mark, I'd be happy to. We are producing… we exited around 4000 barrels a day gross, 27,000 barrels a day net. Most of that production is really coming from the hectare area down in Dunn County, and that's where we began the focus and in '08 it would be a significant focus for us on a development basis. So in hectare area, we’re be producing about 3700 barrels a day gross oil from about 23 wells. Right now, our IPs that we have been seeing has typically been on the order of 300 barrels of oil equivalents, per day pretty much in line with expectation and our e-wires [inaudible] are actually, we were a little encouraged. We think the e-wire is going to be probably more now between 350,000 to 400,000, so a little higher than I think that for original expectation that we had said. So things are pretty much in line with expectation. We did slow down some of our drilling in 2007, which caused a little bit of a reduction in the rate, but we currently six rigs only now and we’ll ramp up into eight in 2008.

Mark Gilman - The Benchmark Company

Thanks a lot, Steve.

Operator

And it appears we have no further questions, gentlemen.

Howard J. Thill - Vice President, Investor Relations and Public Affairs

Thank you. We would like to thank everyone for tuning in with this. And I would like to take this opportunity to remind everyone that our analyst meeting, as we did mention earlier, is coming up March 27 in New York. If you have not a RSVP or if you have not received an invitation, please let us know and we’d be glad to get that to you. Have a great day. Thank you.

Operator

That does conclude today's presentation. We thank you for your participation, and ask that you enjoy the remainder of your day.

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