馬拉松石油 (MRO) 2008 Q1 法說會逐字稿

Good day and welcome to Marathon Oil's first quarter earning's conference call.

As a reminder, this call is being recorded.

For opening remarks and introductions, I will now turn the call to Mr. Howard Thill, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you, Justin. I too would like to welcome everyone to Marathon Oil Corporation's first quarter 2008 earnings webcast and conference call--teleconference.

The synchronized slides that accompany this call can be found on our website: Marathon.com. On the call today are Clarence Cazalot, President and CEO; Janet Clark, Executive Vice President and CFO; Gary Heminger, Marathon Executive Vice President and President of our Refining Market and Transportation organization; Steve Hinchman, Executive Vice President Technology and Services; Dave Roberts, Executive Vice President, Upstream; Phil Behrman, Senior Vice President Worldwide Exploration; and Gary Peiffer, Senior Vice President of Finance and 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 and the Private Securities Litigation Reform Act of 1995, Marathon Oil Corporation has included in its annual report on Form 10K for the year ended December 31, 2007, and subsequent forms 8K, cautionary language identifying important factors, but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements. As most of the numbers will--we will discuss today are adjusted net income. Slide three provides a reconciliation of net income to adjusted net income by quarter for 2006, 2007, and 2008. Turning to slide four, adjusted net income for the first quarter 2008 was $767 million, an increase of about 8.5% compared to the first quarter of 2007, and 53% compared to the fourth quarter 2007.

Slide five compares these same quarters on a per-share basis and shows adjusted net income was up approximately 5% from the year-ago first quarter and about 53% above the fourth quarter of 2007. During the first quarter, we had approximately 717 million weighted average fully diluted shares outstanding and we repurchased approximately 2.8 million shares during the quarter.

Moving to slide six, the year-over-year increase in adjusted net income was largely a result of price and volume growth in our upstream segment and the increase in our integrated gas segments income due to our Equatorial Guinea LNG facility which started operations during the second quarter of last year, mostly offset by a lower refining and wholesale marketing gross margin and higher exploration expense.

As shown on slide seven, the increase in adjusted net income for the first quarter 2008, compared to the fourth quarter 2007, was a result of higher upstream liquid hydrocarbon and natural gas realizations, higher upstream sales volumes, lower exploration expense, and higher contributions from the oil sands mining and integrated gas segments. Both of which were slowed by maintenance activities in the fourth quarter of 2007. These positive effects were partially offset by a lower refining and wholesale marketing gross margin.

Turning to slide eight, Upstream segment income for the first quarter was up $219 million over the fourth quarter 2007 reflecting higher realizations and sales volumes and lower exploration costs and income taxes partially offset by higher DD&A expense. As shown on slide nine, Upstream sales volumes were higher in the first quarter 2008 as compared to both the first and fourth quarters of 2007. Mainly as a result of the full uninterrupted quarter of natural gas sales to our LNG plant in Equatorial Guinea, first quarter 2008 income also benefited from higher average realizations, which increased $1.71 per barrel of oil equivalent or BOE over the fourth quarter 2007.

Moving to slide 10. Domestic Upstream income increased $91 million, from the fourth quarter largely a result of higher realizations and sales volumes and lower exploration expense. This was partially offset by higher income taxes and DD&A and lower other revenue mainly as a result of lower natural gas purchase and resale activities.

Turning to slide 11. Improved differentials for Gulf Coast Sour and Wyoming asphaltic grades and the higher Gulf Coast Sweet and spot WTI premiums all contributed to our significant price realization improvement, relative to the WTI benchmark. Our lower 48 natural gas realizations were higher than the increase in bid week pricing, largely as a result of stronger basis differentials for natural gas sold in the mid-continent and Rockies.

Turning to slide 12. First quarter domestic Upstream expense, excluding exploration expense was $2.17 per BOE higher than the fourth quarter primarily as a result of higher DD&A expense and increased production taxes. Domestic Upstream income per BOE increased $6.74, quarter-over-quarter, reflecting both higher realized prices and higher sales volumes.

Moving to slide 13. International Upstream income for the first quarter increased $128 million from the fourth quarter to $440 million. This increase was mainly due to a reduction in income taxes, higher realizations and sales volumes, and lower production expenses partially offset by higher exploration expenses related to seismic acquisition in Indonesia and seasonal exploration activity from our In-situ assets in Canada. The large decrease in international taxes was the result of year end tax accrual adjustments recorded in the fourth quarter.

As shown on slide 14, our total international liquids realizations increased less than Dated Brent. While our international crude oil prices actually increased in line with Dated Brent, NGO realizations didn't keep up with the price of crude. Our international natural gas realizations decreased $0.77 per MCF due to the increased volumes of the lower priced natural gas sales to the LNG plant in Equatorial Guinea.

Turning to slide 15. International Upstream income increased $4.81 per BOE, primarily due to reduced income taxes as previously discussed, higher liquids realizations, and lower expenses partially offset by lower gas price realization. I would like to point out that additional value from the Equatorial Guinea gas volumes is realized through the LNG facility itself; and the sale of these LNG volumes is reflected in our integrated gas segment.

Turning to slide 16. Oil Sands mining segment income for the first quarter was $27 million, compared to a loss of $63 million in the fourth quarter of 2007, when operations were disrupted by a fire at the Scottford upgrader. Net bitumen production, before royalties was 24,000 barrels per day for the first quarter, less than previous guidance due to weather-related issues at the mine and unplanned maintenance at the Scottford upgrader.

Segment income for the first quarter includes a $36 million after tax loss on derivative instruments, which were put in place by Western Oil Sands prior to the acquisitions, $32 million of which was unrealized. The last of these derivative instruments is set to expire in the fourth quarter 2009. Also during the first quarter, the royalty calculation methodology for the Athabasca Oil Sands Project was revised to allow for additional eligible costs of the project. As a result, the 1% royalty rate was retroactively applied to the project as of July 1, 2007.

Marathon expects a refund of approximately $32 million, with $16 million of that amount realized in the first quarter and the other half as a purchase price adjustment. As shown on slide 17, our total production on a combined basis for the upstream and Oil Sands Mining segment was 399,000 BOE per day for the first quarter of 2008, an increase of about 16% from the first quarter of 2007, and about 9% higher than the fourth quarter 2007.

Moving to our Downstream business, as noted on slide 18, first quarter 2008 segment loss totaled $75 million compared to $345 million earned in the same quarter last year. Because of the seasonality of the Downstream business, I will compare our first quarter results against the same quarter in 2007. The primary factor contributing to Downstream's change in results quarter-to-quarter was the significant reduction in the Light Louisiana Sweet or LLS Chicago 6321 crack spread, which averaged only $0.07 per barrel in the first quarter 2008, compared to $5.26 per barrel in the first quarter 2007. On a two-thirds Chicago and one-third U.S. Gulf Coast basis, the average LLS 6321 crack spread decreased from $5.14 per barrel in the first quarter 2007 to $0.51 per barrel in the first quarter 2008.

In addition, the Company's per gallon wholesale sales price realizations for non-gasoline and non-distillate products did not increase over the comparable prior year period as much as the average spot market price for the applicable product in the LLS 6321 calculation. For example, the average price of all the products we sell other than gasoline and distillates only increased about $0.55 per gallon, whereas the price of 3% residual fuel oil increased by $0.73 per gallon on average quarter-to-quarter.

Our first quarter Downstream results were also significantly impacted by planned maintenance activities at our Garyville, Robinson and Detroit refineries. Primarily because of this maintenance activity, our crude oil throughputs averaged only 845,000 barrels per day in the quarter compared to 968,000 barrels per day in the first quarter last year. In addition, manufacturing expenses were about $175 million higher in the first quarter, 2008, compared to the same quarter last year primarily due to the previously mentioned maintenance activities, light product transportation costs, and purchased energy cost. The first quarter 2008 segment loss includes a pre-tax derivatives-related loss of about $120 million compared to a pretax derivatives related gain of $26 million in the first quarter of 2007.

As Gary Heminger mentioned during our analyst meeting in March, we're transitioning away from the use of derivatives in our p-plus pricing strategy. Partially offsetting these negative factors was an improvement in the spread between gasoline and ethanol prices during the first quarter 2008, compared to the same quarter of 2007. The first quarter 2008 also marks the startup of ethanol production at the 110 million gallon per year Greenville, Ohio, plant that is 50% owned by Marathon.

As shown on slide 19, Speedway Super Americas or SSA gasoline and distillate sales were down approximately 8 million gallons in the first quarter 2008 compared to the same quarter in 2007, or a decrease of 1%. The SSA same store gasoline sales volumes were down 2.4% and the same store merchandise sales were down 0.7% in the first quarter 2008, compared to the same quarter in 2007. SSA's gross margin for gasoline and distillates was about $0.115 per gallon in the first quarter 2008, compared to $0.122 per gallon in the same quarter of 2007.

Slide 20 provides a summary segment data along with a reconciliation to net income . Slide 21 provides select preliminary balance sheet and cash flow data. Cash adjusted debt to total capital at the end of the first quarter was approximately 24%. As a reminder, the cash adjusted debt balance includes just under $500 million of debt service by U.S. Steel. Year-to-date, preliminary cash flow from operations was approximately $800 million and preliminary cash flow from operations before working capital changes was approximately $1.3 billion.

Slide 22 provides guidance for the second quarter and full year 2008. Production available for sale excluding Oil Sands Mining is forecast to be between 355,000 and 370,000 barrels of oil equivalent per day versus 375,000 barrels of oil equivalent per day available for sale in the first quarter 2008. The decrease is largely a result of seasonally lower gas sales in the North Sea and Alaska combined with scheduled downtime at our Equatorial Guinea LNG facilities.

I will now turn the call over to Clarence Cazalot, Marathon President and

Thank you, Howard.

As we've reported, our Upstream segments recorded sales volume in the first quarter of 2008 was 378,000 barrels of oil equivalent per day. I think it's important to note that this represents a growth of 11.5% above the first quarter of 2007 and a 6.6% growth above the fourth quarter of 2007. This growth is mainly attributable to our gas sales in the LNG Plant in EG. For 2008, we're on track to deliver the production guidance discussed with you at our recent meeting in New York of 380,000 to 420,000 barrels of oil equivalent per day despite the delays we have seen in our Alvheim and the outside operated Neptune projects.

At Alvheim, we experienced about a 10 day weather delay in moving offshore but commissioning of the FPSO is nearly complete and we expect first production to occur over the next two to three weeks. Production from the Vilje field is anticipated during the latter half of the second quarter and peak production of 75,000 net barrels of oil equivalent per day from these two fields is expected by early 2009. At Neptune the operator, BHP, advises the repair design is ongoing and they expect to provide additional guidance on timing of completing repairs in the coming weeks. The operator has suggested that first production may occur in the third quarter.

At this point I'll turn it back to Howard for questions.

Thank you, Clarence.

Justin, we will now open up the call to questions. I'd like to remind everyone, for the benefit of all listeners to please identify yourself and your affiliation.

Thank you. (OPERATOR INSTRUCTIONS)

The first question comes from Doug Terreson from Morgan Stanley.

Good afternoon, guys.

In refining, refinery throughput and product sales were lower in relation to the year-ago period, and when Howard was talking about this, he mentioned that planned and unplanned maintenance and I guess indirectly slower demand explained part of the decline; and so my question regards whether idling of capacity was relevant too, and also whether or not you have capacity that is idled today as well and just any color that you can provide on that decline would be appreciated?

Doug, this is Gary.

You're absolutely right in Howard's presentation, the majority was due to planned maintenance and some unplanned maintenance in the first quarter. Very little of it was due to idled throughputs; however, through the quarter and today there are some areas within the country that--you don't keep your reformers completely full, which makes your gasoline portion of your output. So I would say what is being idled right now are just in some regions part of the reformer's side of the business.

Okay, and just to clarify, I think Howard also mentioned that cost and refining were higher by $175 million versus the year ago period and that was really explained by maintenance and purchased energy cost; and so, obviously some of that will be recurring, some of it won't, but do you have an expectation as to how much you can reduce that number by going forward?

Well, here, Doug, we have completed--a little bit of it went over into April as we finished up the Robinson turnover.

Okay.

But the majority of this expenditure was in the first quarter--was all planned, however as I said earlier a little bit of unplanned. Going forward, we don't have anything significant planned at this time over the next couple of quarters and some turnaround activity will start up in the fourth quarter; and Gary has a number here that he'll share with you as well.

Okay.

Doug, this is Gary Peiffer.

Probably about a little over $100 million of that was planned maintenance and activities associated with that. So we're experiencing higher costs in the refineries. So we wouldn't expect, an extra 60 or $70 million every quarter but that is probably the right neighborhood.

Okay, that is great. Thanks a lot.

And the next question will come from Neil McMahon with Sanford Bernstein.

Hi, guys, two questions.

Firstly, just maybe turning back to Angola. There has been a lot of movement in stocks over the last few months associated with exploration discoveries, yet it's one of the areas that has been strange for you guys is basically looking at the combined volumes discovered in blocks 30, 31 and 32. Any update to the Analysts Day presentation? It sort of looks from my calculations that the gross volumes discovered in both blocks are somewhere between 2.5 to 3 billion barrels recoverable somewhere in that order of magnitude. So that was the first question.

Yes, Neil, this is Phil Behrman.

The only update that we can give you is what we have said in the earnings release. We have announced that Portia discovery in block 31 and then we also noted that we have three additional wells that have reached total depth. We can't, obviously, talk about those or which blocks those are on, and those include exploration and appraisal wells. So some will add new volume and some will confirm some of the existing volume that maybe have already discovered by the initial exploration well.

In addition to that we have two rigs currently drilling in Angola. As we've told you before, it's--we're loathe to get out in front of the operators who provide information and we're providing as much information as we can without violating any of our contracts in Angola.

Phil, maybe just a follow up there, have you found it in the geological community a bit strange that so much attention has been put on Brazil, yet nobody's done an addition of all of those discoveries and offshore Angola? Because it seems like people have just become immune to any incremental discoveries there.

I guess it's hard for me to answer what other individuals are saying about exploration areas. What I will tell you is is that the additional discoveries, of course, were not things that we recorded at the analyst meeting and so those will add individual volumes. The impact will be, as we begin to commercialize all of the successes, and of course, as we've told you, with that process starts in 2008, and then we're queuing up these "development areas" in blocks 31 and block 32; and I think sequentially over time, you will see these discoveries commercialized.

And maybe just a final question for both Clarence and Gary.

Given the way refining's been over the last six months and now you're starting to very much hook in the Oil Sands part of your portfolio, might we see any refinery divestments, maybe some of the refineries that are not as hooked into the system as maybe Detroit or Garyville are; might you see a slimming down of the refining side of the business as you start expanding the E&P side of the Company?

Neil, this is Clarence.

We're not in the position to talk about individual assets, but I'd simply reiterate what Janet said at the analyst meeting, which is we're undertaking a portfolio review of all of our assets and that portfolio review is not simply with respect to their financial performance, current and projected, but also the strategic fit we see of those assets in our portfolio for the long-term; and recognizing that we as a company and as a management team are guided by creating and delivering value for our shareholders, you will have to accept that as we look at this, we'll take those actions that make the most sense for the Company; but I'm not prepared to address any specific refinery or any other asset at this time.

Great. Thanks.

The next question will come from Doug Leggate With Citigroup.

Thanks. Good afternoon, everybody.

The integrated gas business looks like had a pretty decent contribution this quarter. Can you help us get a little bit of an idea what the split was between the LNG facility and the balance? It looks like your capture under the contract you have with BG may have been a little better given the environment than perhaps your guidance had suggested in the past? Then I have a follow-up.

Doug, this is Dave Roberts.

I guess I would point you to a number of things, obviously, because of our commitments to BG, we can't discuss what the nature of the S-curve looks like. But I would remind everybody that we're FOB sellers at the facility. We have previously pointed out a single point on the curve that should give you a relative guidance point. That is at $6 Henry Hub, we have an FOB net of $3.45 to Marathon; and the other thing I would point you to is we did 24 cargos last year, 15 in the first quarter of this year and hopefully with that bit of information, you can start to triangulate around why the segment was so much more profitable for us in the quarter.

Okay, great and the follow up is on tax.

In your corporate line you always have this corporate tax adjustment and this quarter that seems to have taken you down to the low end of your guidance range on tax. Is there anything specific to Q1 that has caused that and should we be looking towards the lower end of the guidance range or maybe just give us some color and how we should think of that going forward?

Sure, Doug, this is Janet.

That corporate line does tend to bounce around particularly in the first quarter because, of course, we're on 1018, where we try to determine what our effective tax rate will be for the full year; and so as the mix changes during the year, you're going to see that corporate adjustment, adjust; however, in the first quarter, there were a couple of items that I will call your attention to. We did get a $49 million tax benefit related to the deferred tax liability that we have in Canada, and if you looked at the 10K, you would see that when we booked that acquisition it was a $1.5 billion, U.S.

You also remember because the Canadians lowered their federal tax rate we had a special item, about $200 million benefit, so you can imagine that starting the year we are about $1.3 billion of U.S. So as the Canadian dollar weakened during the first quarter, we got a reduction of that liability and therefore, a benefit. That was the biggest item, that plus mix change is expected throughout the year.

Okay. This one final one from me if I can.

This is on Oil Sands this time. You mentioned in your prepared remarks, Howard, that you were starting to try and cop exploration activity on the In-situ. Can you maybe just elaborate around that a little bit in terms of what we should expect? Because clearly those are bookable reserves, and not something I don't think that was factored really too much into the acquisition of Western when you did at the time.

Well, Doug, this is Dave Roberts.

I would say that we indeed, did factor in some of the values for the In-situ because obviously, we wouldn't have gotten that for free. But what the activity related to the amount that we expended was 63 wells drilled on our Ells River property that we have a 20% interest in and Chevron is the operator and some associated seismic spend; and 21 wells drilled in the 100% owned Marathon Birchwood property. The analysis of those well results and the course taken is ongoing and it will lead to potentially decisions in the future, not in the near-term about how the properties may be developed.

Okay, that is great. Thank you.

Moving on to Paul Sankey with Deutsche Bank.

Hi. Good afternoon.

The buy back level is notably lower in Q1. Is that a new ratable level that we should think about or is that kind of on its way to zero as we go through the rest of the year? Thanks.

Paul, this is Janet.

Yes, as we said at the analyst meeting in March, we're continuing to do the share buyback program, albeit at a modest level. Don't necessarily expect it to stay at the rate, we could accelerate it or we could slow it down. We still have the expectations that by the end of 2009, we should be able to complete the balance of the authorization that was out there; but, that is one of the beauties of the stock buyback program is you do have that flexibility to either accelerate it or slow it down, depending upon what your opportunities are.

Thanks, Janet.

And Gary, if I could, an update on your major CapEx projects as they're going on in the Downstream. Could you just give us the very latest on Garyville and Detroit? Thanks.

Sure. At Garyville, we're approximately 47% complete right now on time, on budget; and that is, we have the major of the engineering complete, Paul, and we're heavy into the construction phase. So that is going very well.

In Detroit, it was just yesterday, was another public hearing on the permit and we should hear within the next couple of weeks on the stage of the air permits which would be required for construction, so we're continuing to move forward on our engineering on that project.

Thanks, Gary.

If I could just leave you with an open question and that will be it for me. You did make an interesting observation at the analyst meeting that you expect very low levels of utilization to persist in U.S. refining. That has proved to be a very solid prediction. Is that still your view of how we'll go through the summer?

Secondly, any observations you had on demand, you've given some same-store sales numbers here that look a bit scary. If you could add any color around that, that would be terrific and finally, any interesting observations you had on ethanol and I'll leave it there? Thank you.

Okay, first of all on utilization, as we expected--turnarounds, Paul, in the first quarter, we expected them to be higher and as we go into the second quarter, I would say the turnarounds, where we see them will slim down significantly and it's all going to depend on the spreads and it's mainly utilization, I think, that is going to be driven by the spreads of the bottom of the barrel. If can you get asphalt and [resid] prices to--for the margins to equate much closer to the costs accrued, you will see the utilization go up; but I would say where we stand right now, we would expect utilization to continue to struggle and be at the lower end.

As far as same-store sales, the numbers that was in Howard's speech, as we go through April, we're seeing about a still a 2% decline in year-to-date but about 1% to 1.3% for the month of April declining same store gasoline sales. I'll say on the distillate side looking at our total market on distillate, we're seeing a slowdown in freight traffic across the country, closer to a 4% to 5% slow down, part of that is going on rail but I think just a slowing down of the economy.

Lastly on ethanol, as ethanol and corn prices have moved around and there were ethanol, this price vis-a-vis gasoline it continues to be a strong blending component; and ethanol year-to-date in the paths that we market, looks like ethanol is up about 120,000 barrels per day over the same period last year. So as I say, it continues to be a strong blending component and continuing to see it growing in the lower part of pad 1.

Thank you.

Moving on to Robert Kessler with Simmons & Company.

Good afternoon.

I have got more of a strategic angle to the utilization question. That is just looking simply at your total throughputs, albeit that they're down quarter-on-quarter and year-on-year. You still got over 1 million barrels of oil running through your refineries, and then you just look one line down on your slide at the Chicago 6321 crack running at a mere $0.07 a barrel. It sort of begs the question why not throttle back even further? I am sure there are complexities in terms of contractual commitments and the like and just turning refineries on and off in any given quarter, but maybe if you could address the conceptual idea of why not pull back further.

That is a fair question, Robert and we look at that every day. The crudes we're buying, what the market prices, especially in Chicago, what the north south differentials are; and you're correct when you can't hurdle the north south differential, either you have enough inventory within pad 2 to be able to supply your customers, or if you can transport it up through the pipelines and cover the transportation cost, it would make more sense to refine it in the Gulf Coast.

So we do look at those numbers every day and in making our determination of the right way or most efficient and optimal way to run the refineries and going back to Doug Terreson's question, as far as anything shut in, you always look at that last barrel that's going in the refinery. Your base utilization going through your process units pretty well will line out your refineries, but usually the last 5% or so of the barrels that you really have to be careful of and believe me, we look at those every day very carefully.

Fare enough. Thanks, Gary.

Next question is from Erik Mielke with Merrill Lynch.

Good afternoon and thanks for taking my question.

My questions relate to the production for 2008, and your guidance where you've got 380 to 420. What would take to you the lower end of the guidance range and what would take you to the upper end of that range; and as part of that question, could you also address your expectations, for Equatorial Guinea for Q3 and Q4, given how strong it was in the first quarter and the maintenance that you highlighted for the second quarter?

Yes, Erik, this is Dave Roberts.

I guess without speculating too much on how you could reach either end of the ranges, obviously, the lower end could be reached in the event that we had unforeseen difficulties with bringing our two major projects on this year, which as Clarence has highlighted, we certainly don't expect given our growing day-to-day confidence that Alvheim is within weeks of coming on stream.

In terms of upside, again, it will be reliability and performance of those two projects because they're a significant--significant opportunities in Alvheim about how quickly we get the projects to ramp up, but we'll see. We have taken a reasonable engineering approach for how we think the fields will come online.

With respect to the facilities in Equatorial Guinea, as Howard mentioned, we'll take a 15 day shutdown in the second quarter, which will impact our volumes in the quarter, basically that will be the first turnaround of the facility. We'll be able to do some debottlenecking there, so we would expect Q3 and Q4 to be at least as strong as the first quarter and we'll see if we can potentially upgrade the throughput of that facility to give us some additional volumes as well.

Okay, that was very clear, thanks.

I have a follow-up question for Janet on dividends. You announced your dividend for the second quarter yesterday or for the first quarter to be paid in the second quarter and you've kept it flat. Is that what we should expect for the rest of the year, given your earlier comments on buybacks as well?

Yes. We look at the dividend every quarter and make that decision on a quarterly basis, we don't do it ahead of time so I'm not going to speak for the rest of the year. But at the analyst meeting we talked about the fact that we recognized the dividend as an important component of total shareholder return and in fact, one of the charts that I showed there had modest dividend increases embedded in it on an annual basis. So it's not a promise, but it's something that we look at and seriously consider.

Great. Thank you.

This question will come from Paul Cheng with Lehman Brothers.

Hey, guys.

A number of hopefully quick questions. Gary, when we looking in the second quarter, how much is your crude purchase is going to still be tied to the P plus 1?

Paul in the second quarter, as we mentioned, Howard had in his speech and as I talked there in March in New York, we have started to decrease our use of derivatives and to mitigate crude oil price risk and I really don't want to get into it. As we're switching over, I really don't want to go into the exact percentage as can you understand for competitive reasons as you're out trying to buy crude oil; but in the second quarter, we have started that and as we look going forward, we do not believe this change will affection our income significantly.

Okay.

Should we assume that the second quarter we're not going to see much of the derivative gain or loss already?

I would say a minor portion in the second quarter because we didn't start completely on April 1, but we have made a significant dent in that derivative activity.

And, Paul, this is Gary Peiffer

When you start in April, that is really for May business or if you start in March, that--you've got the prior month you're always dealing with and all this also so it's not always as clean as you might expect it to be.

Sure, fully understand. That is why I asked it. How much should we assume--

Right.

Or expect it.

There will be a little bit of a transition. March was really--your purchasing in May. Some April, some May, depending on how you're buying it. But it will transition out in the first couple of months.

Sure. Seems like two gentlemen, may be I can ask two other questions along the (inaudible - highly accented language).

Gary, when I looking at your operating stack, you're talking about in the first quarter refining and supply the margin is a negative $0.024 per gallon. In the fourth quarter, you say it's $0.048 of profit it, and if we look at the sales volume and we do the math, that means sequentially from the fourth to the first quarter, your operating profit job in the supply and refining by about $280 million or about $170 million after tax. So, I'm quite surprised and pleasantly surprised to say that you only lost $75 million in the quarter, but I have some difficulty that why you only lose $75 million; where is the other $75 million loss associated with the refining and supply margin lost that where we pick up the benefit?

Okay, Paul, as Howard mentioned and as we try to mention in the earnings release, we're a seasonal business. Not only from a standpoint of our sales but also kind of the expenses that go along with that. So we always compare and we always talk about light quarters, not sequential quarters. So when we were given our interim update or interim guidance update as well as the remarks here that Howard just gave, we kind of compare everything quarter-to-quarter.

Now, if do you it sequentially like you do it, we kind of get a different mix of variances, obviously; and primarily, the biggest affect that we get when you go from the fourth quarter of '07, which is a calendar year-end, to the first quarter is we don't have as many expenses typically in the first quarter--non-manufacturing expenses in the first quarter as we do in the fourth quarter.

We have less transportation costs, because we sell less. We have less--some of our incentive compensation accruals that we're truing up in the fourth quarter as you might recall. We did have a very good year last year. So as we true those up, we don't have the same outlook this year. So you get a totally different mix of expenses quarter sequential to quarter.

And Gary, is that $100 million pretax?

It's a big number, that's right. So I guess when you look at us and probably most other refiners, I think it's best to kind of look at what are those deltas calendar quarter to calendar quarter not sequentially.

Okay.

Gary, when I looking at $27 million in profit, you have $36 million in derivative loss and--but you also gained $16 million in the royalty refund. That means that on [trailing] basis that is a $47 million after tax, but that seems to suggest that an operating cost of about $67 per barrel. That seems too high. Are we doing something wrong in this calculation?

I don't have that type of--level of detail here, Paul. Let me try to work on a reconciliation and get it back to Howard to get to you.

Okay, that is great.

Janet, different subject. Do you have an effective tax rate by division or for the year and also the second quarter?

I think we have just given guidance for the full year effective tax rate.

You gave guidance for the full year for the full corporation, but do you have it divided by divisions?

I don't think we have given guidance on that. Have we, Howard?

Not--we do not have that today, Paul.

Okay.

We have that internally, obviously, but we have not provided that externally.

Is it possible that you guys can share that number?

We will discuss it and get back with you, Paul.

That would be great. And for David, for Alvheim in Norway, when you finally come on stream, what is the unit [DD&A] and cash operating cost. that should we assume?

Paul, I'll have to get back to you on that as well. I don't think we have given that level of detail for single asset.

No, we don't. We don't give that kind of detail on single asset, Paul.

Yes, because we assume that, given we have some delay and cost overrun, the DD&A could by pretty high?

Paul, we did give the F&D cost on the full Alvheim Vilje project at the analyst meeting and we would not expect any significant changes from that.

Okay. I see. Okay. Very good.

(OPERATOR INSTRUCTIONS)

Next question will come from Mark Gilman with Benchmark.

Folks, good afternoon.

What percentage of that derivative loss, the $120 million-odd was not offset by physical market effects in the first quarter?

Mark, this is Gary Peiffer.

I don't have that number, we don't really track it that way. So we believe that they're all offset in some fashion, it's just that they always don't happen in the same quarter because we mark-to-market everything. We don't try to use hedge accounting on our derivative activity. So, it's all offset, it may just not be in the same quarter.

Within the quarter, Gary, give me a ballpark. Is it 10% or 80%?

I don't know. I would be purely guessing.

Okay.

What I can tell you, though, is of that $120 million, about $81 million was due to managing price risks, so that's kind of how we buy our crude oil. The other $45 to $46 million was due to inventory where we had excess inventories that we build up that we were hedging the price on and the rest of it was kind of a miscellaneous breakdown between other categories. Most of it was driven by mitigating price risk, and as you know, the structure changed to the point in the first quarter of '08 where we were a negative $0.41 on structure versus like $1.25 last year Contango. So some of that is structure just happening and the rest of it is just the fact there was a price increase of about $6 or $7 from the end of the year to the end of the first quarter.

Okay. Given the royalty situation in Alberta and the change in cost allocation for the purposes, when do you expect payout to be achieved now based on whatever price assumption you want to utilize to answer the question?

What?

Go ahead.

That is something we would let the operator speak to. That is not something we would get ahead of that on.

Okay, let me try another one.

I think you said that the Alvheim Vilje was now going to peak in early 2009. It was my understanding that you've predrilled the development wells there and if that is accurate, why so long a ramp?

Mark, this is Dave Roberts.

That is a fair question. What we did say is by early 2009. It kind of goes back to my earlier statement about we have taken, I have gotten in trouble for using this word before, but we have taken a very prudent course in terms of how we think the various fields and wells are going to ramp up over the course of the year and that is the reason we're using that language.

We do--we have a number of wells drilled and ready to go and we have them sequenced throughout the remainder of the second and third quarter and how they're going to be joined to the production facility, and a lot of that depends on how those wells perform when they're brought on and making sure that we manage the reservoirs properly. So, it will be an engineering decision as we bring the wells online.

Okay, I've got one for Phil Behrman if I could.

On the Stones appraisal well, Phil, can you talk at all about the pay interval you encountered and what the location was relative to discovery?

Mark, we can't talk about a lot of things on that because we--and let me give you a little bit of context for it. We had a lot of operational problems and a lot of the data we would like to have collected we were not able to because of these operational problems. That being said, we were further up dip from the original hole.

We were probably in the range of about 400 feet further up dip towards the crest of the feature; and as I mentioned, we encountered sands, hydrocarbon field in the lower tertiary, obviously all the hydrocarbons are oil. That's about the limit at what we can say. We're still meeting with our partners because the data is still coming in on the well and as we get consensus of the partnership on all the interpretations of what we've encountered from this date, I think we can be a little more forthcoming; but we're hampered at this point because we're still getting the data.

Okay, one other production oriented question if I could.

Will you produce liquids in EG during the time that the LNG facility is shut down?

Yes. The gas is actually turned back to the field, Mark, it doesn't slow down the gas production; it just goes back to recycling like we did before the LNG facility came on stream.

Okay, so the liquids won't be impacted. It's merely the gas which you will re-inject instead of selling it?

That's correct.

Okay, guys, thanks very much.

Well, with that, we would like to thank everyone for joining our conference call and have a good afternoon.

That does conclude today's conference. We do thank you for your participation.