馬拉松石油 (MRO) 2007 Q4 法說會逐字稿

Good day, and welcome to Marathon Oil's fourth quarter and full 2007 years earning 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.

Thanks. 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 Gary Peiffer, Senior Vice President of Commercial Services Downstream. Slide two 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 important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set 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 2006.

As shown on slide five on a diluted per share basis, adjusted net income for 2007 was down 15% for -- 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 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 a result of a lower refining and wholesale marketing gross margin and lower up stream sales volumes partially offset by lower income taxes.

As shown on slide 7 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 up stream segment and lower income taxes. Fourth quarter 2007 results were also negatively impacted by higher expiration expense which was primarily related to dispensing noncommercial wells 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 tailed by Western at the date of acquisition. Segment income was also impacted by a mid-November fire and subsequent curtailment of operations at a Scottsburg upgrader during the fourth quarter. The upgrader returned to operation in late December.

Slide eight compares adjusted net income for the fourth quarter 2007 to the third quarter 2007, and shows the decrease was primarily a result of a lower refining and wholesale marking gross margin as well as the previously mentioned higher expirate and natural gas realizations and lower taxes.

Turning to slide 9, the $274 million decrease in 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 tax and high realizations.

As detailed on slide 10, upstream segment income 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 expiration 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 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 2007 to the fourth quarter 2007.

Moving to slide 12, domestic upstream income for the full year, 2007 decreased $250 million from the year 2006, largely as a result of lower sales volumes and the higher expiration 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 expiration expense.

As shown on slide 14, the NYMEX 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 expiration expense was $0.71 per BOE lower than the third quarter, while domestic upstream income for BOE increased $0.63 quarter-over-quarter.

On slide 16 you'll 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 realizations increased $1.58 per MCF compared to the third quarter. Largely as a result of seasonally higher spot and natural gas prices in you'reon and lower gas volumes of gas sales to our LNG facility in Equatorial Guinea due to the plant shut down from early-October to mid-November. Please remember that our LNG business is reported through the integrated gas segment so there is additional uplift in value realized by the EG LNG facility that is not recorded 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 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'll 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 forecast for the upstream segment.

Thank you, Howard. The 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 U.S. and 51 million internationally. In both areas, about equally split between liquid hydrocarbon and natural gas. The additions are primarily the result of drill bit activity, including onshore U.S., Alpine Beauty of Development drilling and infield 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 proven 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 proven 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 new major development projects. Our reserve replacement expectation on a rolling basis remains at greater than 100%. Our 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. The shortfall is not due to our base production, which has consistently performed within expectation. It is caused by delays in production startup of development projects. The most significant are 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 products were to start production in the first quarter of 2007. We now expect start up at the end of the first quarter 2008. The initial expectation would have resulted in nearly a full year of production in 2008 at FPSO capacity. Now we have both the delay start up and the production ramp up, new high wells in and optimize the operation all occurring in 2008. We expect to move the FPSO out of [Hoggoson] in mid-February. We'll need to stop in Amaford where we can install the structures and do some additional commissioning that also requires deeper water. We expect this will take about ten days and then we'll sail to the field. The biggest threat at this time is having the necessary weather window as we move and position the vessel.

In 2006 guidance the Neptune project in the Gulf of Mexico would start production at the beginning of 2008. The operator now expects it will be at -- the 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 if missed by even a few months could have a significant impact on our quarterly and annual production estimate but we maine remain confident that our growth guidance from 2006 to 2010 of 6 to 9% is achievable.

Now turning to cost guidance. 2007 operating costs, excluding FAS 144 impairment, production tax, owing royalty and exploration, fell within the guidance provided. For 2008, we expect operating costs on a similar basis for the U.S. 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.

Thanks, Steve. We appreciate that update. Moving to our downstream business. 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, compared to $533 million earned in the same quarter of 2006. Because of the seasonality of the downstream business, I will compare our fourth quarter result against the same quarter for 2006. The average LLS 6321 crack spread for the quarter on a two-thirds Chicago and one-third U.S. Gulf Coast basis was weaker in the fourth quarter 2007 compared to the fourth quarter 2006, decreasing 25% from $3.19 per barrel to $2.39 per barrel.

The most significant factor contributing to the downstream segments 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 used in the LLS 6321 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 2006 to the fourth quarter 2007 whereas the average 3% residual refuel oil price used in the 6321 calculation increased almost $0.67 per gallon on average quarter-to-quarter. In addition, our crude oil costs 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 backward dated market in the fourth quarter, 2007, which averaged about $1.33 per barrel. The change in the market structure substantially increased our acquisition costs 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 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, 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 2007 primarily due to higher planned turn around expense and other maintenance and salaries. Marathon's refining and wholesale marketing gross margins included 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 effects of closed derivative positions 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 related to 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 program due to the relatively lower ethanol prices compared to gasoline prices during the fourth quarter 2007 versus the prior year quarter.

We completed major turn arounds in the fourth quarter at our Catlassburg, Robinson, and St. Paul Park refiners, primarily involving our fluid catalytic cracking unit at all three plants. Therefore while crude oil 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 2007 which were down 6 million gallons or a decrease of 0.7% from the fourth quarter 2006. SSA same store gasoline sales volumes were down 1.3% and same store merchandise sales increased 1.1% in the fourth quarter 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 a reconciliation to net income.

Slide 25 provides selected preliminary balance sheet and cash flow data, catch adjusted debt to total capital at the end of the fourth quarter was approximately 22% and as a reminder, this cash adjusted debt balance includes just under $500 million of debt serviced by U.S. 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 what Steve just discussed. I will now turn the call over to Clarence Cazalot, Marathon President and CEO.

Thank you, Howard, and good afternoon everyone. It's 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 higher than expected exploration expense and unscheduled down time both at EGL NG and the Athabasca oil sands project. We are not satisfied with that performance especially as to those areas we can control. But taken in it's 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 EGL NG and our oil sands business, these significant growth plans were incorporated in the $8 billion capital and exploratory expense budget we announced yesterday. I would 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.

Most of the $2.8 billion increase represents new investment opportunities rather than the cost of inflation. In fact a majority is related to totally new projects. Our Canadian oil sands assets will be investing $900 million in 2008. The Detroit heavy oil upgrade project which our Board sanctioned last year will account for about a $700 million increase. As you know we were a successful bidder in the Gulf of Mexico lease sale last fall. About $155 million will be awarded -- we expect be awarded in 2008 and will be part of our 2008 capital budget.

I'm sure you're 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 suspending 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 $100 million of incremental capital in 2008 for missing infrastructure to support our refining operations. We have an incremental $125 million for Angola appraisal and development and so that remains about -- at $300 million for increased spending of some smaller E&P projects and some cost escalation. In addition, because of the higher level of activity, our capitalized interest will be up about $120 million for the year.

Thank you, Janet. And 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 would be appropriate for Janet to comment on the financial flexibility and wherewithal that we have to carry this out.

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

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

Thank you. (OPERATOR INSTRUCTIONS) And we'll begin with Robert Kessler from Simmons and 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 on in the year to help meet that organic funding requirement but can you speak to the ability to meet in the meantime the CapEx funding in the early part of the year with cash flows from operations and to what extent you might let the debt level grow a little bit throughout the course of the year and also whether or not you might pull back a bit on buybacks until you sell some assets?

That's 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 prudent business in terms of trying to have our capital invested in those projects where 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 from 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're very committed to total shareholder return and we did recommence the share buyback program in the fourth quarter. I think we've said before that we do not 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.

Okay. Thanks, Janet.

(OPERATOR INSTRUCTIONS) And we'll take our next question from Mark Flannery from Credit Suisse.

Hi. I have a fairly simple question about the oil sands expenditure, particularly with regard to AOSP, which I guess is most of it. The $900 million or so 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?

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

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

We are, knock on wood here, Mark, we're running a little bit of 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're just running a little bit ahead of schedule on the site work. So it's just bringing forward, as we put this -- this budget together over two years ago now and had our charts and progress planning, we're just a little bit ahead of where we had anticipated to be at the time.

Right. Okay. Thank you very much.

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

Hi. I've got a few questions about the reserves. First of all just looking at on shore U.S., Steve, I think you said 37 million was what you booked in the year for new additions of the drill bit and I was just wondering what was the flexibility around that given the fact that we had an end year price of over $90 so did that influence booking at all? And then maybe a question for Phil. Just to go into the resources that you feel in Angola and in other places that are yet to be booked under preFID. Thanks.

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

Neil, with regards to Angola resources, I think in spring we'll have an analyst meeting and we'll give you an update of our resources we've 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.

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

Neil, this is Steve Hinchman. Yes, we would expect that a development in block 31 would come to sanction in the first quarter of 2008. And I would say, Neil, to the point of the first sanction of 31 northeast, if you look at most of Thill's exploration success, one of the few areas we've booked reserves thus far is Alvheim Vilje obviously with the sanction of that project. None of the Angola success nor Droshky, our 2007 discovery in the Gulf of Mexico has been booked. It would be primarily on Alvheim Vilje and Neptune would be where we have booked reserves associated with the exploration success we got.

Okay. Great. Thank you.

And next we'll hear from Arjun Murti from Goldman Sachs.

Just to follow-up on some of the downstream spending. Even with the $200 million dollar acceleration in Garyville it still seems like a decent sized 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 follow-on CapEx in '09 and '010 can we expect in the downstream?

Arjun, just give me a second here. We're getting all the capital here over the next couple of years but your second question on what type of response will we get from Detroit in this year, we would not expect any of the coker or any of that benefit to come into us until 2010, 2011.

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

Oh, I'm sorry. Gary Peiffer here has all the individual numbers. Let him go over them with you.

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

About 700.

Yes. About 700 million there in Detroit. So 1.7, 1.8 in Garyville and about 700 -- 1 million or so in Detroit.

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

One minute. Maybe I'll get back to you on that Arjun. I'm still looking it up here.

No problem. Thank you very much.

(OPERATOR INSTRUCTIONS) And next we'll hear from Nicki Decker from 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 effect future performance and whether there is any flexibility?

Yes. Nicki, this is Gary. 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 -- intended to mitigate the price crunch related to that future crude. And what they have on on a yearly basis, they have about 20,000 puts and 15,000 calls for 2008 at a collar of 50 -- $50 floor, $90 ceiling and then 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 to mitigate that, you look at the collar and I guess what it is here of course, an opportunity loss that we had last year. We're aware of this going in. But at this time we do not see anyway to -- anything that economically would justify buying our way out of that position.

Of course, Nicki, when you have a costless collar, you have to mark to market both components of it and to the extent tha the price stays within that collar, we would not necessarily ultimately be out any cash. So if prices stay where they are, you could see that reversal as those hedges mature.

Thank you.

And next we'll hear from Paul Sankey from Deutsche Bank.

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 you can.

I'll answer that Paul, from the upstream. We continue to not put on any equity hedges either on natural gas or on oil. And Gary, do you want to take the downstream.

Sure, Janet. Paul, I think you're well aware that it's always been our acquisition strategy to try to price our feedstocks as close we can to when we use them to produce the products and we're not changing that strategy. We're continuing to look at it and evaluate 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 and we're looking at it but at this time we have no major changes in strategy that we've decided on at this time.

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

No.

Okay. Maybe not. I must have been mistaken. If I was just trying to get to the underlying performance of the Scottford, do you have an idea of what the opportunity costs there were in 4Q so we can get an idea of what you typically might make on that asset if we were at a more normal level of operation? Thanks.

I'll answer it this way, Paul. We went down, I believe it was November 15, or so is when we went down. We believe and we were up to that time averaging about 30,000 barrels net 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 detail, the expense over that period of time. But as I said, we were running at around 30,000 barrels per day and expect as lower mentioned in his discussions, that should continue to be our approximate run rate here going forward into 2008. But I'll have to get back to you with the detailed expense. You'll realize they haven't -- they're still finalizing all of the billings and everything so all of that isn't in, yet, Paul, for December.

I've got you.

And next we'll take Doug Leggate from Citi.

Good afternoon, everybody. My question is on Janet's comments regarding disposables. Can you give us some idea, I'm sure you've probably got a reasonable idea what might make it into that program. What sort of magnitude you would anticipate in terms of the size of the disposable program, where the focus in terms of what assets, upstream or downstream might be targeted and I guess specifically, we all know you've got some fairly long-dated -- I guess reserve potential in Angola. Does some or part of the Angola position make it into that disposable program at sometime in the future?

Doug, this is Clarence. II guess I would say that there is no specific focus upstream or downstream. It is a review of our entire portfolio of assets. We do not 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 business 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 do not, then we will not 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.

All right. Thanks, Clarence.

Next we'll hear from Paul Cheng from Lehman Brothers.

Hey, guys. I think that the first one is that Howard, when you found out that the cost for the oil sands fire, can you also give me a call?

Sure. We can do that, Paul.

That would be great. I guess my question is to Gary. I understand in the past why you want to do the P plus one in your acquisition but when you're looking at that, does it really accomplish anything? I mean over the long haul in a back rotation market or in a contango market that you have a reverse impact and so over the long haul there is a net zero in terms of value but there is a cost associated with managing that kind of a program, so it end up there to be a net loss all the time, you're just creating move volatility in your earning, comparing to what other people are looking at that, so I'm not sure that this is really for the benefit of the Company when you're a far smaller company or the industry in a more difficult time and constantly worry about cash flow, maybe the bank required, but I can't imagine the bank require you guys to do something like that today, so maybe you can help me to understand a little bit better why you insist to continuing doing it that way?

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

And more importantly, is there any way that you do not hedge your product side of your selling price so why even bother to hedge. If two sides of the equation let you know that you get the cash flow, what is your true cost and what is the product price you're selling, if you do not hedge the product price why do you want to hedge the crude price.

Well, the product price is really the big unknown. We're trying to bring the crude price into sync with what is going on in the market on that day. So--.

I understand that, Gary. But what I'm saying to you is that is still not going to get you the net result to have a longer cash flow or margin anyway because you don't know what is -- one end of the pricing going to be.

That's correct. And as you well 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 and make it on the margin rather than on the price change.

And Paul, this is Gary, we take your point. We understand. 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 Gary said. The question you have, you've paid 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.

Gary, can I sneak in one soft question.

One last one, Paul.

What is the pilot truck stop year-over-year sales on the truck stop over 12 months?

Just on the distillate side, Paul?

Yes.

That's the most meaningful number. It was around 4% on a same store basis, quarter-over-quarter. 4.3 to be exact. But 4.3% year-over-year increase. Thank you.

Thanks, Paul.

Next we'll hear from Mark Gilman from Benchmark.

Folks, good afternoon, Clarence I assume that of the two two major upstream development projects you referenced in your comments that the Northeast section of block 31 Angola is one of them. Which is the other one?

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

So contingent upon the appraisal well you're drilling?

Yes.

My unrelated follow-up goes back to this downstream number. I know you like to look at the comparisons versus a year ago, in which case the backwardation versus contango structure is relevant; however, if you look at it 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'm wondering is, what kind of derivative impact is in there versus 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?

Mark, this is Gary Peiffer. I think the biggest contributor to a fourth quarter '07 to third quarter '07 is if you look at just the LLS 6321 crack, in the third quarter it averaged on a two-thirds Chicago, one-third Gulf Coast basis about $9 a barrel. Fourth quarter on that same two-third, one-third basis it was $2.39 a barrel. So we lost about $750 million of value or profit just because the market swing from the third to fourth quarter. To your question on contango backwardation, in the third quarter we were in contango on average about $0.39 and we we $1.33 as Howard said negative in the fourth quarter. So there was about a $75 million swing right there. And as you know, our delta of profit profit quarter-over-quarter was off about $750 million or so. So the lions 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.

Gary, anything in the way of mismatched derivatives that burns the comparison you just talked about?

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

But you get some sweet sour and light heavy help on that too.

There is definitely pluses and minuses. No doubt about it.

Okay, thanks guys.

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

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

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

Okay, thanks.

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

I think we need one more derivatives question so I'm going to go ahead and ask it. And it really goes back as a clarification to Gary's comments regarding the collars, position size, et cetera. Were those comments related to the derivatives losses in the 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.

Yes. Doug, that was all oil sands. The 20 million barrels of puts and 15 of Pauls were on oil sands.

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

That's correct. He was talking about market structure.

Absolutely, I just wanted to be sure. Thanks.

Okay.

(OPERATOR INSTRUCTIONS) We'll take our next question from Mark Gilman from Benchmark.

This one is for Janet. Janet, can you give me a rough idea in the purchase accounting allocation for Western what percentage of the PP&E was allocated to producing versus nonproducing?

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

Okay. Thanks a lot.

And next we'll hear from [Bernard Forn] from [Polaris Capita].

I'm just wondering 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 seem to recall they had some stuff in the Mideast, I don't know if that's something that you've discussed or was part of the deal.

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

So they halved that off before you purchased it the?

That's correct. They turned that off, was a company called Western Zagrose.

Okay. Thanks a lot.

If there's no more--.

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

Okay. Steve Hinchman, I'm a little bit surprised at the low level of the Bakken production in the quarter. Give me any 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?

Mark, be happy to. We're producing -- we exited around 4,000 barrels a day gross, 2700-barrels a day net. Most of that production is really coming from the Hector/Ajax area down in Dunn county and that's where we've begun to focus and in '08 it will be a significant focus for us on a development basis. So in Hector/Ajax area we're producing about 3700 barrels a day gross oil from about 23 wells. Right now our IPs that we've been seeing have typically been on the order of 300 barrels of oil equivalent per day, pretty much in line with expectation and our EURs are actually -- we're a little encouraged, we think the EUR is going to be probably more now between 350,000 to 400,000 so a little higher than I think the original expectation we had set. So things are pretty much in line with expectations. We did slow down some of our drilling in 2007 which caused a little bit of a reduction in the rate. We currently have six rigs running now and we'll ramp up to 8 in 2008.

Thanks a lot, Steve.

And it appears we have no further questions, gentlemen.

Thank you. I'd like to thank everyone for tuning in with us 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 RSVPd 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.

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