馬拉松石油 (MRO) 2005 Q3 法說會逐字稿

Good day, everyone, and welcome to this Marathon Oil Corporation third quarter 2005 earnings conference call. Today's call is being recorded. For opening remarks and introductions, I would like to turn the call over to Mr. Ken Matheny, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Thank you very much, Patty, and I too would like to welcome everyone to the third quarter 2005 earnings webcast and teleconference for Marathon Oil Corporation. Let me begin by reminding you that if you are listening via telephone, you can find the synchronized slides that accompany this call on our website at www.Marathon.com.

With me on the call today are Clarence Cazalot, President and CEO; Janet Clark, Senior Vice President and Chief Financial Officer; Phil Behrman, Senior Vice President of Worldwide Exploration; Steve Hinchman, Senior Vice President of Worldwide Production; and Gary Heminger, Executive Vice President and President of our Refining and Marketing Transportation Organization; and Garry Peiffer, Senior Vice President of Finance and Commercial Services for our downstream organization. Approximately two hours after this call ends, these remarks and the slides will be placed on the Investor Relations portion of our website. It will remain on the site for one year.

Slide No. 2 contains the forward-looking statement and other information related to this presentation. Our remarks and answers to questions today will contain certain forward-looking statements that are 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 31st, 2004, and in subsequent Form 10-K and 8-K filings 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 shown on Slide No. 3, net income for the third quarter was $770 million, and included two special items totaling a negative $27 million after tax, resulting in net income adjusted for special items of $797 million. The two after-tax special items were a negative $48 million mark-to-market loss on our two long-term UK gas contracts, and a $21 million gain on the sale of a 15% interest in Equatorial Guinea LNG Holdings Limited.

Net income adjusted for special items of $797 million was $42 million more than the second quarter of this year, and 168% greater than the the third quarter of last year. The sequential improvement as well as the improvement year-over-year was largely a result of the elimination of the minority interest in our downstream business, strong refining and marketing margins, along with record refinery throughput, and increased liquids and natural gas prices somewhat offset by lower upstream production sales. A reconciliation of net income adjusted for special items to net income is included on Slide 3. You can refer to Slide 2 for a discussion of the use of this non-GAAP measure.

Moving to Slide No. 4, net income adjusted for special items on a per share basis, equal to that of the second quarter at $2.16 per diluted share, but I will note that approximately 19 million more shares were outstanding this quarter. The additional shares outstanding were largely a result of the downstream minority interest acquisition we closed on June 30th.

As shown on Slide No. 5, third quarter segment income was $1.435 billion, $175 million less than the second quarter, but almost double that of the same quarter last year. A major factor in the decrease from the second quarter was lower upstream sales volumes, partially offset by higher liquid and natural gas prices in the upstream segment. Worldwide upstream sales volumes were down, largely as a result of liquid hydrocarbon underliftings in the United Kingdom, Equatorial Guinea and Gabon, and the four storms, two of which were major hurricanes that hit the Gulf of Mexico during the third quarter.

Upstream segment income of $627 million is shown on Slide No. 6. It was down $149 million quarter-over-quarter. Domestic upstream segment income of $397 million is shown on Slide No. 7, was relatively flat for the second quarter. Domestic liquid realizations were up over $10 while natural gas was up a less robust $0.80. Again, production sold was adversely affected by the significant storm activity during the quarter in the Gulf of Mexico.

Slide No. 8 demonstrates how domestic upstream income benefited over $100 million from higher prices, while lower volumes reduced operating income in the segment -- operating income in the segment by approximately $60 million compared to the second quarter. Other revenues were $27 million lower during the quarter, primarily as a result of the gain on the sale of East Cameroon block 321 that occurred in the second quarter. Other fluctuations, mainly increased production taxes in the current quarter and second quarter insurance related to Petronius amounted to a negative $17 million.

Total expenses in the domestic upstream segment, as shown on Slide 9, were up $2 per barrel of oil equivalent compared to the second quarter. Excluding exploration expense, which can vary based on the timing of dry holes, expenses were up $2.32 per barrel of oil equivalent from $14.64 to $16.96 per boe. This increase is largely a result of the higher production taxes related to higher commodity prices, increased per barrel operating cost due to reduced volumes, higher G&A allocations, and lower insurance recoveries related to Petronius. For the year, we'd expect on a barrel of oil equivalent basis domestic field level expenses to be $3.35 to $3.40, DD&A of around $6.70, and all other costs, excluding production taxes, to be about $4. At current prices, domestic production taxes are approximately $2.10 per barrel of oil equivalent.

Moving to Slide 10, domestic upstream income per barrel of oil equivalent increased 10% over the second quarter, reflecting the 18% increase in the average liquids and natural gas realizations, partially offset by the previously discussed increase in the average cost of barrel equivalent.

Moving to international upstream, as shown on Slide No. 11, international income of $230 million was sharply lower than the second quarter, mainly as a result of the timing of international liquids in the United Kingdom, Equatorial Guinea, and Gabon. Slide 12 shows that the underlift in international hydrocarbon sales reduced international upstream income by over $200 million, but this was somewhat offset by lower DD&A of $42 million, again related to those liftings. Higher price realizations increased in segment income $20 million, while exploration expense was $34 million higher in the second quarter, primarily a result of writing off the Annapolis well offshore Nova Scotia. All other changes amounted to a positive $31 million for the quarter, mainly a result of lower controllable costs, due to the timing of liftings.

Moving to Slide No. 13, total international upstream sales volumes decreased 32% compared to the second quarter, while liquid hydrocarbon sales volumes decreased 36%, again, primarily a result of our underlift positions. Lower natural gas sales volumes were the result of lower spot gas sales in the United Kingdom and higher injections to storage in Ireland. International upstream expenses excluding -- excluding exploration expense increased approximately 10% on a barrel of oil equivalent basis compared to the second quarter, primarily the result of higher Russian production taxes, and increased expenses associated with a start-up of our Equatorial Guinea LPG plant and lower volumes and a change in production mix due to our underlift position.

For the year we'd expect on a barrel of oil equivalent basis international field level expenses to be approximately $3.45 per boe, DD&A of around $7, and all other excluding production taxes to be about $4.25. At current prices, international production taxes are approximately $2 per barrel of oil equivalent.

Slide 14 shows that international upstream income per boe fell 13% compared to the second quarter, largely the result of the higher exploration expenses in previously discussed higher production taxes and our chang in mix quarter over quarter. Including the upstream segment discussion, despite losing approximately 20,000 barrels of oil equivalent per day as a result of the storm activity in the Gulf of Mexico, production available for sale was within 1,000 barrels a day of the estimated production range for the quarter, as a result of strong performance from other regions, primarily in Russia, and Equatorial Guinea.

Moving to our downstream business in Slide 15, third quarter segment income of $814 million was more than double the $391 million third quarter 2004 segment income. And because of the seasonality in the downstream business, I will compare the third quarter 2005 results against the same quarter in 2004. The single largest factor contributing to the downstream improvement was a significant improvement in crack spreads. On a two-thirds Chicago and one-third U.S. Gulf Coast basis, the WTI 3-2-1 average for the third quarter was $17.53 per barrel, compared to $7.37 per barrel in the same quarter last year. The WTI 6-3-2-1 crack spread, which better approximates Marathon's total production rate, also improved substantially, increasing from about $3.02 per barrel in the the third quarter of 2004, on a two-thirds Chicago and one-third U.S. Gulf Coast basis, to $10.70 per barrel in the third quarter.

Just the improvement in the WTI 6-3-2-1 crack spread would have added about $800 million to downstream earnings compared to the third quarter of 2004. However, the rapid increase in spot market prices used in these indicator crack spreads, particularly in September, was only partially passed along to our wholesale and branded customers. In addition, the price of our non-gasoline and non-distillate products traditionally lags a life product spot market price changes. These two factors had a negative effect of approximately $500 million when compared to the indicated WTI 6-3-2-1 crack spread increases.

The crude oil in transit effect was a negative $37 million in the current quarter, versus a negative $70 million in the third quarter of last year, a $33 million positive impact. All the other variances last quarter resulting from the record total refinery throughputs we achieved at our refineries last quarter, wider sweet/sour differentials, which were partially offset by higher expenses and other costs, accounted for the remainder of the quarter-to-quarter variance.

As shown on Slide 16, Speedway SuperAmerica's gasoline distillate sales were up about 31 million gallons quarter-over-quarter or about 4%. Same-store gasoline sales were up about 5%, even though Speedway SuperAmerica's retail gasoline prices averaged $2.45 per gallon in the quarter just completed, compared to $1.81 per gallon in the same quarter last year. Speedway SuperAmerica's merchandise sales on a same-store basis increased almost 11% last quarter from the same quarter last year, and this marked the 11th consecutive quarter that Speedway SuperAmerica's merchandise sales have increased over 9% on a same-store basis.

Turning to slide 17, the integrated gas segment incurred a $6 million loss during the the third quarter of 2005, compared to income of $11 million in the second quarter 2005. The decrease was primarily the result of mark-to-market changes in the fair value of derivatives used to support gas marketing activities. In the unallocated category, administrative expenses were $108 million in the third quarter. The increase from the second quarter total of $85 million was due primarily to an increase in the non-cash charge related to equity-based compensation, as our share price increased by more than $15 during the quarter.

Net interest and other financing costs were $32 million in the third quarter, $3 million lower in the second quarter, largely a result of higher capitalized interest, partially offset by reduced interest income in the current quarter. Pretax income for the the third quarter was $1.2 billion, and the tax provision was $469 million for a 37.9% effective tax rate. This was higher than our guidance, due to adjustments to income tax accruals and the tax treatment of certain derivative instruments, and we now expect our tax rate to be in the 36 to 37% range for the year.

Cash adjusted debt went up by $182 million during the the third quarter to $3.286 billion. Cash adjusted debt-to-capital September 30th, 2005 is approximately 24%, and I'll note that that cash adjusted debt balance continues to include approximately $587 million of debt that's serviced by United States steel. I will remind you, these are preliminary numbers. Third quarter preliminary cash flow from operations was approximately $449 million. Preliminary cash flow from operations before working capital changes was approximately $1.05 billion. And for the first nine months, preliminary cash flow from operations was approximately $1.963 billion and approximately $3.27 billion before working capital changes.

Finally, Slide 18 provides information from prior quarters, as well as estimates for the fourth quarter. Total liquids production available for sale in the fourth quarter is expected to be approximately 186,000 to 199,000 barrels per day. The increase over the third quarter is expected as a result of lower hurricane down time. Worldwide gas production is estimated at 980 million to 1 billion 25 million cubic feet per day, higher than the third quarter because of seasonal gas sales in Europe and Alaska, and, again, lower hurricane downtime in the Gulf of Mexico.

Total production available for sale for the fourth quarter therefore, is estimated at 350,000 to 370,000 barrels of oil equivalent per day. While we cannot predict the exact timing of liftings, given our significant underlift position of approximately 2.5 million barrels at the end of the third quarter, production sales for the fourth quarter are likely to fall between the production available for sale just provided and 380,000-barrels of oil equivalent per day. Finally, we now estimate 2005 production available for sale to be between 340,000 and 350,000 barrels of oil equivalent per day, excluding the impact of any acquisitions, dispositions, or of our potential re-entry into Libya.

Now I'd like to turn the call over to Clarence Cazalot who will provide comments about our results and forward plans.

Good afternoon, everyone. Marathon had another very strong operational and financial quarter despite the storm disruptions. And thankfully our employees and their families didn't sustain any significant injuries during the evacuations or during the storms. And I'm really very proud of the way our employees have responded in an extraordinary manner, restoring operations both upstream and downstream shortly after the storms. But their response did not stop there, as the Company and our employees along with our dealers, jobbers and wholesale customers have now contributed over $8.5 million to the relief effort.

I think as I spoke to you at the last teleconference, we continue to focus on safety and environmental stewardship. Through September, we continue to have lower rates, both in safety and environmental incidents, almost across the board in our operations. As compared to both 2004 and compared to our goals for 2005. It's an area in which we will continue to remain focused and vigilant.

Because of the hurricanes during the quarter, our entire Gulf of Mexico production was down from what amounted to more than one full month. While this reduced production and sales about 20,000 boe per day, as Ken already said, we were fortunate in that we didn't sustain any major damage and have been able to bring back our production on stream to over 90% from the Gulf in a very timely manner. During this period, we had very strong production results from Equatorial Guinea and Russia that helped to offset some of that reduced Gulf of Mexico output. EG Phase II, which is the liquid expansion, both condensate and LGP continues to exceed our expectations. And in Russia, our East Kamennoye Vickulov [ph] development continues to perform well, with total Russian production now in the 30,000 barrel per day range and I would remind you that at the time we made the acquisition, in mid-2003, production from that asset was 15,000 barrels per day.

Our development projects are progressing as planned. The Alvheim Vilje project in Norway is 29% complete and progressing on schedule, and we continue to look at options to tie back the 2004 Hamsun discovery to this development. And as Ken mentioned, we continue to have exploration success, with our two Angola discoveries in this quarter, bringing the total discoveries in blocks 31 and 32 now to 12.

The Equatorial Guinea LNG Train 1 project is now 58% complete and ahead of schedule. With about $1 billion expended to date, it is also on budget, with first LNG deliveries expected in 2007. And we continue to move forward with our studies and our work towards justifying a second train there on Bioko Island.

Let me turn to the down stream. In the first quarter, which we now had 100% ownership of the downstream operations, we set a new record for total throughputs at almost 1.2 million barrels per day, and this was done in spite of its disruptions from the two major hurricanes that reduced our total throughputs by about 40,000 barrels per day for the quarter. Again, I think another testament to the dedication and the hard work of our employees and really the value of this business.

We also took the Detroit refinery down September 29th, to tie in the expansion and the low sulfur facilities and the refinery is now expected to be back in operation by mid-November, taking this refinery from 74,000 to 100,000 barrels of crude throughput per day. And finally, moving to Slide 20, we announced this morning that we are entering the front-end engineering design or the FEED phase for an expansion project at our Garyville refinery in Louisiana. We have completed our feasibility phase of that project, and expect the FEED to take up to a year, which will likely place our final investment decision in the fourth quarter of next year.

With an estimated cost, preliminary estimated cost of $2.2 billion, this major expansion would add 180,000 barrels of crude throughput to this already large 245,000 barrel per day world-class refinery. With major new components, including a crude unit, coker, reformer and hydrocracker, this will be a major undertaking. Importantly, it will also allow us to better balance volumes through the existing facilities at Garyville, expand our use of heavy high sulfur crude and utilize existing pipelines and storage facilities. Once completed, this expansion will enable Marathon to supply the nation with nearly 6 million additional gallons per day of ultra clean fuels, including gasoline and distillates. This project provides an outstanding strategic fit to our existing refining network, including accessibility to numerous product transportation systems that serve key markets throughout the U.S.

In addition to completing a successful FEED, we will need the necessary permits and a continued favorable investment climate to move forward with this project, but we believe the expansion of our Garyville refinery demonstrates the kinds of substantial capital investments we are making in both our upstream and downstream operations to help us meet the growing energy needs of consumers while providing what we believe to be superior value growth for our shareholders.

And with that, I'll turn it back to Ken.

Thank you very much, Clarence. We will now open the call up to questions. I'd like you to please identify yourself and your firm affiliation for the benefit of those listening in. And please limit yourself to one question and one follow up so that all callers may be accommodated. Patty, you can go ahead and bring on the questions.

Thank you. [OPERATOR INSTRUCTIONS]. Our first question today is from Mark Flannery from CS First Boston.

Hi. Yes, I would like to talk about Garyville, actually talk about any other investments you might be planning around the portfolio. Clearly, Garyville is one option for you. Are you actively looking at other things that could be done, either to increase refining capacity or increase the complexity of the capacity that you have?

Yes, Mark, this is Gary Heminger. Mark, as we have said publicly before, and we really had not talked about Garyville earlier, but we are also looking at other conversion capacity options, strategies that we may have, and we talked about some conceptual design we have worked on, in and around Detroit and Katlisberg [ph], and other Midwest plants. So we can continue to study that, but we're a ways away from making any final decisions.

Great. And just -- I don't know, this may be for Clarence. It's a follow-up question. Is -- what is the constraint here free CapEx or is it identifying the right project or is it -- is it a combination of both? How do you think about capital allocation into the refining side of the business?

Well, Mark, I think one of the things we've said all along and even going back to the time that we -- we discussed how, indeed, the upstream might be 60% of capital employed and downstream 30%, integrated gas 10% that was a view we had of the world a couple of years ago that suggested upstream opportunities, integrated gas opportunities might be more plentiful than our downstream opportunities. I -- but I also said at that time, that capital would flow to the best projects, those that created the most value for the Company as we saw it. And I would say today what is emerging for us are some really quality downstream opportunities.

I think Garyville sort of leaps out as an obvious one in terms of its position, and the opportunity to expand that capacity, and increase the crude flexibility, but there's -- there's no capital constraints. I think as Janet has talked quite a bit before, we've got considerable financial flexibility, and we're simply going to allocate capital on the basis of where we see the greatest value creation for the Company, and I think that's -- that's what you see reflected in the Garyville project.

Great. Thank you very much.

We will go next to Paul Cheng from Lehman Brothers.

Good afternoon, guys. Clarence, I think before you acquired the minority interest in MAP, one of the rationale behind it was you could use it as a vehicle for you to expand the debenture into some of the upstream area that you may otherwise may not have opportunity, including in the [inaudible]. I wonder now that you have 100% interest on that, is that being changed now? Do you now look at it just as a [explicit] good investment opportunity or often you sell but not necessarily tied to the upstream?

No, I think, Paul, it sort of goes back to Gary Heminger's comments just a moment ago. We continue to study investments in our Midwest refineries that would certainly allow them to process a heavier crude slice than they're able to today, and so our interest in those kinds of opportunities continues. That's about all I will really say about where we stand on that.

I would simply go back to my prior point, though, at the end of the day, what we're going to really judge is -- is what's the best value proposition for the Company? Indeed, if it's integrating backwards into the upstream and participating in an overall integrated transaction, then that's what we'll do. If, indeed, we believe we can capture greater value, simply letting people compete for crude access to our refineries then that's what we'll do. But to have the opportunity to judge between those two options, we think is -- is precisely where we want to be and the kinds of flexibility we want to have in capital allocation.

Can I have a follow-on that's not exactly relate to the subject. Where are you on the exploration well in Nova Scotia from the past, I think considers explorations assessed. Does that mean that your view on Nova Scotia that as the exploration pay [ph] has changed now.

Yes, Paul, this is Phil Behrman. What I'd tell you is is that no, the view has not changed recently at least. What we did is recognized that due to the SEC requirements that we had to have activity within this area within the last year. Since we didn't have that activity, we followed those rules and wrote the well off. We are currently talking to government officials, as well as our partners in looking to see about the possibilities of drilling a well in 2007, and depending upon the outcome of those discussions, we have plans to consider drilling a well in 2007. We also have the possibility of re-entering the Annapolis well because we still have the well head in place. We just have to see where our discussions go and we'll take it from there.

Thank you.

Thank you very much, Paul.

We will go next to Neil McMahon from Bernstein.

Hi, guys. This is a question just on page 12 of your slide pack. Just going back to this -- the volume issue, you've got negative $311 million associated with volume losses from the international space. I wonder if you could just walk me through the components of that volume loss, both in terms of the liftings and the down time or decline rates, whatever. How much of that should we expect to come back in the next quarter?

Yes, Neil, this is Steve Hinchman. The majority of that is in our underlift. For the quarter, our difference between our sales volume and our available for sale is around 45,000 barrels per day, so a large part of that is just the timing of those liftings. We are also a bit lower on our gas sales and that's primarily as a result of lower gas, spot gas sales in our UK, primarily from Brae. And, we are choosing to sell gas more in the winter quarters the first and fourth quarters to take advantage of the higher price environment.

Maybe just a follow-up on that. That would assume pretty amazing margins that you are getting on your volumes for your owner [ph] list and just wondering, are those locked in in terms of getting them, because they could have been lifted at that time. And I suppose secondly, what is there to stop this -- not stop this from happening again in the next quarter?

Well, the -- the Brae volume is a big part of the underlift, and, actually, we established the price of that during the time that we sell it. So we're not exposed to the lifting from one quarter to the next in price. The price is set at the time that we actually make the sale. And our Brae volumes are relatively higher margin volumes and those are locked in. And in our UK contracts we are expected to balance throughout the year, so we should make up a significant amount of the underbalance that we have now in the fourth quarter.

So we should expect a good chunk of that 311 to come back in the fourth quarter effectively?

Yes. Yes. I mean, sometimes there's a lifting that occurs on December 31st or January 1st. Sometimes that gets a little too close to call, but -- but we endeavor to come to an annual balance.

Okay. Thanks.

And we will take a question from Jennifer Rowland from J.P. Morgan.

Thanks. A question on the Garyville expansion. Did you assume in your preliminary analysis that there might be some potential incentives coming down from Washington? If you could just comment on that and how you are thinking about any potential legislation, that would be helpful.

Yes, Jennifer, in fact, we have looked at many different things that are being discussed in Washington, and other state houses. It's really too early to come down to a definitive answer and as Clarence mentioned, in his comments and Ken in his remarks, that over the next year, as we finish up the feed work, and understand exactly where the business climate is in D.C., that will be a plus or a mine to us this project. But we certainly are on top and understand, what has been legislated under Energy Bill 1, and we're keeping close tabs on further actions that are being discussed at this time.

Okay. Great. And then if you could remind us where you stand on ultra low sulfur diesel for next year. Are you already ready to go for those specs in June or are you seeing any project delays as a result of contractor and supplier issues post the hurricane.

No, Jennifer, we are in good shape. We feel confident that we will meet the June 1 deadlines, and as we have illustrated before, we will have approximately -- just a little bit less than $60 million, Garry Peiffer, I believe that number is correct?

Right. About the 900 or so that we will spend to meet both gasoline and ultra low sulfur diesel, we will expend about -- all but about $60 million as of the end of this year.

So that's all we have left, Jennifer. The majority of that work is in the Midwest. So I think we're in very good shape to meet the June 1 deadline.

Great, thank you.

And we will go next to Nicki Decker from Bear Stearns.

Yes, good afternoon. Gary, do you have a sense for what your turn-around schedule looks like early next year?

Yes, I do. It's always been our policy, Nicki, to not divulge our overall turn-around schedule, you will see -- normal maintenance, early in the year that we have historically have had, to do some of our crude heater cleanouts and some of our corporate spalling and -- but that's really all I can discuss at this time.

Okay. And also, Gary, on the same-store sales, maybe you could just give us a little color on what sales look like by month. Particularly in the month of September, year-over-year.

Same-store gasoline you mean?

Yes.

I would say -- in fact, let me go and -- I have it by quarter here. I don't have it by month. Garry, do you have them by month? I don't have them with me.

Were you asking gasoline or merchandise?

Gasoline.

Gasoline.

Yes, I think we've -- I guess just basically we start out very strongly in July and then it tapered off through September. One thing that maybe we need to point out is that last year, same quarter we were down on gasoline in same-store sales, so to a certain degree, somehow we are seeing this year as kind of catching up, but we definitely did because that 5% same-store increase, we did definitely take some market share this year in the third quarter, but I would say, it was stronger in July, and it was about average in August and tapered off in September a bit. It was still positive in all three months.

Yes, and I -- I just found my -- my numbers here. We are not at the same office today, Nicki and Garry was right. In September, we ended up being about 2% but that was against a market that appears to be down around 3% in gasoline, overall gasoline market for the U.S., and -- and August and July, obviously if we are up 5%, we are much stronger. So there were effects of the -- of the hurricanes and the disruptions in the marketplace in the September month.

Thank you so much.

And we will take a question from Doug Terreson from Morgan Stanley.

Good afternoon, everyone. In trying to better understand the variances in your downstream value chain, I wanted to see if you could relate how margins at wholesale trended for the Company between Q2 and Q3 of 2005, and also where that spread may be today? Meaning, I think that Ken mentioned in his opening comments that there was a $500 million Delta and if I heard him correctly related to pricing lag effects in relation to the year-ago period, and so I wanted to get clarification on that point, that is to just make sure that I heard it correctly and to try to understand that factor in relation to the most recent quarter too, so that we can better understand those variances.

Right. And, Doug, let me first explain a little bit of this and then ask Garry, he may have the exact numbers with him there.

Okay.

But what has happened in the -- and really happened of course in September, you really look at the NYMEX or the posting of the U.S. Gulf Coast, you look at those crack spreads, that indicates what in normal market conditions, how your wholesale and how your pricing to the Street should follow.

Sure.

And under extreme volatilities in those periods of time, never seeing that type of volatility in the past, competitively, the markets did not move anywhere near what the -- the NYMEX and some other indicators were moving. So that's why there's such an extreme lag effect, if you will, during the month of September, because of that. And Garry, do you have the individuals?

I'm not sure exactly of the question, but I guess just maybe on a similar basis as Ken said, in the third quarter, '05, to third quarter '04, if you just look at the 6-3-2-1 effect, you would have expected that our income would have been up about $800 million if we were a merchant refiner, if you will, but because of the pressures Gary talked about, net, we were only up about $300 million quarter-to-quarter, on our realizations at the wholesale level, and we also include in there also the fact that the bottom of the barrel, which we produce, doesn't move as quickly as the spot gasoline, and spot diesel prices that were quoting move. So it's the combined effect of all of those.

Now if you go to the second quarter of this year, '05 to the third quarter of '05, that Delta of about 300 I referred to earlier, we catch about 150 of it, we would estimate in the third quarter. So if you look at the 6-3-2-1, third quarter to second quarter we would have been up about 500 million on a similar basis to the 800 that Ken mentioned. But we only achieved about 350 million of that 500 -- or excuse me, we did not achieve about 350 of the 500. So about 150 Delta. So a little bit -- we captured -- we didn't have as big a decrement, but the second quarter was already in a higher spot to begin with.

And, Doug, really to get to the balance of your question, here in October.

Right.

We are seeing the Street is much more transparent -- the wholesale, I should say is much more transparent to what you are seeing the cracks on the different indexes.

Okay, Gary, that answers the question. Thanks a lot.

All right.

We will go next to Doug Leggate of Citigroup.

Thank you. Good afternoon, everybody. My question relates to West Africa. First of all, Angola. There's, again, been fairly standing success over there in terms of the exploration. I'm just wondering where you stand now with your partners in terms of the potential sanctions, potential project outlook, because clearly if you look at the magnitude or the scale of some of the similar projects in that area, the potential volume impact on Marathon, even though it could be five to seven years away is still very, very significant. So an update there please would be appreciated along with any additional well exposure over the next 18 months.

Doug, this is Phil Behrman, currently on the status quo of what we told you before, in block 31 northeast, we are continuing with our feasibility studies to enter FEED in 2006 and project sanction [ph] about a year after that, so we are on track for that area. In block 31, also we had a number of discoveries in the southeast part of the block and we have a rig full time for 2006, and we plan to continue to drill in the area for the rest of this year and through 2006 and into 2007 drilling exploration wells. And we'll continue to mature that area for potential commercialization.

Okay. So -- go ahead.

Go ahead. In block 32, we're currently drilling. On block 32 on the mustarta [ph] prospect, and when we complete that, we'll assess that area for commercialization, and we'll recommence drilling next year with a rig and potentially two rigs during the year on block 32. All targeting towards moving those closer to commercialization.

Okay. My follow-up if I may on West Africa is just to ask Clarence to elaborate on the progress towards a potential phase II LNG project, project in EG. I'm thinking in terms of what role the government is playing in terms of bringing together potential stranded gas partners and just what the likely time frame could be on a decision there.

I think, Doug, it's a cooperative effort, first of all, the EG government is fostering relations with both Nigeria and Cameroon in terms of cross boarder issues and sourcing gas from those countries. We continue to work with our partners, our new partners, Metzuni [ph] and Merivini [ph] and G-patrol in terms of the further analysis on that plant. We are probably nearing a decision on a front end engineering and design program for that project that would commence before the end of this year. So, I think all of it is coming together nicely, both in terms of the sources of natural gas, and -- and ultimately the design and engineering of the plant itself. So it's moving as we would expect.

Just so I understand you correctly, Clarence, did you say you are expecting a decision on front end engineers before then of this year.

Yes.

Okay. Thank you.

We will take a question from Paul Sankey of Deutsche Bank.

Good afternoon, gentlemen. On the Garyville expansion, can you talk a little bit more about the extent to which the Garyville refinery will be down in the buildup period and when the investment would start?

Yes, Paul. This is Gary. First of all, we need to reiterate that during 2006, the majority of 2006, we will do all the engineering and design before we go back to the Board for final approval. So, we are looking for any construction, if it were to be approved and we were to get all of our permits streamlined, like we are going to need them to be, to be able to start construction in that window. But this is going to be a brand new separate train that would set adjacent too and we're going to leverage off the infrastructure that is there. We have not gone out into the pre-planning at all, but we are looking at kind of '09 time frame before you would start doing any tie-in and using common pipelines or common tankage, and to that point we may have very little down time, if any, to be able to tie the systems together.

That's interesting. Thanks. If I could have a follow-up on a separate subject. The guidance you offered for the fourth quarter is excellent. Could you talk a little bit about '06 in terms of some of the metrics you've outlined, production and the other things that you've talked about for the fourth quarter. Could you just look into '06 as well for guidance, please?

Paul, I think that this is probably a little bit preliminary, but the guidance and the range that we had given last February are probably still very much in order for '06.

Okay. That's great. Thanks.

And we will go next to Chris Moore from Merrill Lynch.

Great. Thank you. Another question on Garyville. Could you maybe discuss how you can see the crude slate changing after the expansion?

Sure. Our -- our plans right now it would be almost a duplicate of the crude slate from a gravity, sulfur standpoint, as it is today. We run a basket of medium sour to heavies, Arab heavy and then really get into ultra heavy with mia [ph]. So it would run pretty much the same basket, but I don't want to necessarily say that we will run the exact same crudes. We will continue to look at what is the best integration across the global crude network to determine down the road what is best for us.

Okay. Separate question, you gave an update on the CapEx for the LNG project and that being on budget. Can you talk about the rest of your portfolio, what you are seeing in terms of capital spending and if there's any inflationary pressures?

I think that at least in terms of development capital, in '06, we're pretty much on our planned volume. We are seeing some amount of inflationary pressures. A lot of it has to do with the mix. We have a majority of our capital is in major projects where we are actually locked in on the cost. Where we are seeing in our portfolio, the majority of inflationary pressure is really in the domestic U.S. spend, which we are seeing approximately 20% inflation in the domestic U.S. from '05 into '06, that accounts for us about $50 million. So it's there. But in our mix and our overall portfolio, it's not terribly substantial.

Gary, do you want to comment on the downstream?

Yes, certainly. For the balance of '06 -- excuse me, the balance of '05, we are in very good shape. We had some minor increases, more on raw material costs than labor. But very minor and insignificant to finish up our -- our clean fuels and the Detroit project which will be finished up mid-November and pretty much the way Steve outlined. We are bidding out some work for '06, we are seeing some inflation issues but, again, rather insignificant because we don't have a real large construction budget going into '06.

Just one quick follow-up on that, the $2.2 billion for Garyville, I -- you have -- you are assuming, I guess that there's continued inflation in that figure?

Yes. In our initial estimates of that, you know, we worked with the major EPC's who work on these big projects. So we have taken into account what we expect the inflationary pressures to be by the time we would be constructing that facility.

Thank you.

And we will take a question from Mark Gilman from Benchmark Company.

Good afternoon, guys. This is primarily for Phil Behrman, I wonder if he could elaborate just a little bit on the three wells that are mentioned in the press release in terms of the Marathon interest as well as prospect sizes. I'm referring to the Aquarius, the Davan and also under the appraisal on Gudrun.

Sure, Mark. Generally we don't give up front estimates on prospect sizes but for Aquarius, we are at a 50% working interest. That's a deep shelf well in the Gulf of Mexico. For Gudrun, that's an appraisal well in the Gudrun prospect in the Norwegian's North Sea. We have 28% working interest. And Davan is in the UK North Sea and we have a 20% working interest. That is an HBHD well

Okay. If I could just follow up a little bit. In terms of the second potential train, at Bioko Island, I'm getting the sense that you don't anticipate having the resource capability to fill that train on the basis of your own licenses and are looking to third party sources, is that inference correct?

That's correct, Mark. I think we said all along that while we have additional resource on our existing acreage from some of the other discoveries we have made in the area, there's no question that we're going to need additional gas, both from within EG, as well as from some of the neighboring countries Nigeria and Cameroon and, of course, one of the real attractions, as we've discussed before is there's a considerable amount of gas not very far from the Bioko Island that's either undeveloped, stranded, for lack of a market, or is being flared. So we think the regional gas hub is the ideal solution to commercialize those gas resources.

Okay. If I could overstay my welcome just one more, on Garyville, expansion, I'm getting the impression that for all intents and purposes, and I'm looking a little bit at 12,000 plus for daily barrel on the cost side, that what you are essentially doing is building a new refinery alongside the existing plant with there being little infrastructural benefit of having the two next to each other. Is that accurate?

No, Mark. I believe we have tremendous infrastructure synergy, but when we look at building Cokers, hydrocrackers, a new state-of-the-art crude unit and you look at the cost pressures that -- within the world of what those new facilities cost, but, no, we are -- we are using pipelines, we are using tankage, we're going to have to build some new dock facilities and some new tankage but not as much as you would have to have from ground up. So I think there are a lot of synergies. I do not have all the details as far as a -- because we didn't go and calculate what it would cost to build a brand new ground up without any of those synergies in place but there's a significant amount of synergies there.

Okay, guys, thank you.

[OPERATOR INSTRUCTIONS] We will go next to Albert Anton, Jr., from Burnham Securities.

A question on Garyville. It seems to be a lot of those. In the list of units, you do not list a cracker, and I wonder does this indicate that the output of the plant might be aimed more towards middle distillates than the gasoline or can you expand the existing cracker in the first unit?

No, that -- we're sorry. Maybe we didn't communicate it right, but we are going to build a hydrocracker.

Okay. It's not listed on the slide.

Okay. Our -- our mistake. There would be a hydrocracker, a Coker, as well as a crude unit, and some reformers and other things.

Do you have an idea of the size of the hydrocracker?

We have some ideas on the size. Of course, we don't have that finished yet, but I would say it's somewhere north of 60,000 barrels per day, probably less than 70 but we don't have the process absolutely engineered yet.

That's a pretty big unit.

Pretty big unit. And our cat cracker there today is 130,000 barrel per day unit, so it -- it's one of the largest cat crackers in the country. So this will be a great parallel unit.

And this is Garry Peiffer. This will allow us to essentially fill up that cat cracker that Gary referred to with our own internally produced cat feed, which today we buy from the outside.

I see. Thank you very much.

And we have a follow-up question from Paul Cheng from Lehman Brothers.

Hi. Gary, you talk about the same-store sales trend in July, August, September, do you have any data for October?

Yes, I do and I will say that we need to be very cautious with the numbers in October and the same with the numbers in September, when you've had the tremendous change in the marketplace and how we have moved barrels from pad to pad and people have changed their buying patterns during this period of time, I'm not sure how much credence you can put on these numbers. But I would say on a same-store basis in October, we're seeing pretty much the same pattern as September. Slower than early part of the third quarter, but we're still positive on a same-store basis to last year. And a lot of that is the cause of -- first of all, we've had really no restorations or price increases here in the month of October, and -- and that really benefits us on a same-store basis.

And, Gary, I presume that is including Speedway, as well as Marathon?

Well, that -- the process [ph] I used is only Speedway because we do not set the price on the retail side on the Marathon brand. So I'm really giving you the Speedway side of the business.

Okay. And on [inaudible] let's assume that if you are going to pursue your current plan when you complete, what is the incremental gasoline, and middle distillate as well as [inaudible] is going to be?

Yes. What we're -- just a second here. Okay, what we're looking at would be approximately a split -- it would be about a 50/50 split between gasoline and then jet fuel and also low sulfur diesel. Both kind of in the 170 -- excuse me, both in the 70,000 or so barrel per day range.

So that 70,000 barrel per day in gasoline and 70,000-barrel per day in the middle distillate including the [inaudible] diesel and the jet fuel together?

That's correct.

I see.

Paul, we have other calls that have re-queued, so we'll have to thank you.

Thank you.

And we do have a follow-up question from Paul Sankey from Deutsche Bank. Paul, your line is open.

Hi, sorry guys. Just for the guidance for next year, is it your intention to have an analyst meeting next February? Should we be looking towards that?

We have no plans February, we don't have a firm date, Paul. We are looking at something more towards the middle of the year.

Great. Thanks.

And we will go next to Ted Isaac from Bear Stearns.

Yes, hi, good afternoon, everybody. My question is on -- you previously answered the question about the refining margins and so forth and you mentioned the lag effect. Were you locked into any contracts with customers or do you -- have you done any sort of hedging that might have factored into those results?

We do not -- we have contract to customers, but our contract to customers for the most part are buying at RAC or some index to RAC. So nothing that would really impact those numbers. And as far as any hedging that would significantly impact those numbers, Garry, you have the details there. Could you answer that part of the question?

Yes, on the margins, in fact we did have some crack spreads. We have sold forward in the quarter that we recorded about a $12 million negative effect on for the quarter. And we also had some activity because of some ethanol contracts. We -- we blend quite a bit of ethanol here at MAP and last summer we identified some opportunities to lock in some relatively low prices for ethanol. So we hedged some of those contracts, not all of them by any stretch, and we recorded about a $44 million loss associated with that. Now that's not in the margin. We treat that as other income, but we did have some losses associated with some ethanol hedges that we had, that will not be bought until the -- for the next two years. So we did have a couple of those items but the big numbers that we referred to earlier, there was about a -- the crack spread is only about $12 million that -- that $500 million effect that Ken referred to.

Okay. My second question then, I had to drop off for a few minutes so you may have already been asked this, and I apologize if so. Your financial position is obviously very strong at this point, and do you see yourselves doing any sort of strategic or M&A type activity going forward here?

Paul, we wouldn't comment on strategic M&A activity on this call.

Well, on the product side, I mean -- you have no comment at all? Or --

Well, I'm not sure what you mean, production M&A. Paul, we've said that we feel very good about the growth program we've got in the plan today. The production forecast we've given in the past are being confirmed and that's strong growth, we think better than most of our competitors 5 to 9% growth so, I don't feel compelled to do some kind of acquisition. I think as we said before, we always remain mindful of what's available in the market place. But, we've got, I think, a wealth of good organic growth opportunities in this Company that we think are value accretive, the Garyville opportunity we announced today is a good example of that. So that's the course we are on.

Okay. Great. Thank you.

Patty, we're right up at the end of our hour. We will take one more question.

Okay, and that question will be from Mark Gilman from Benchmark Company.

Yes. Thanks. Another one for Phil. Any Deepwater Gulf of Mexico drilling planned during the fourth quarter or in the early part of next year? And Phil, if you could just comment. The deep shelf has not been something that you guys have pursued aggressively in the past, is there a change in thinking here?

Right now, mark, good question. First of all, regarding the deep shelf, the well that we're drilling is a 22,000 to 23,000 foot well in the south [inaudible] area in and around the facilities that we own, so it's an area where we have deep local knowledge. So what I would say is -- we are taking advantage of a unique niche opportunity adjacent to our infrastructure in terms of that well.

In terms of Deepwater drilling, we don't have anything planned for the remainer of this year but we will be giving our plans. It's pretty similar to the plans we outlined last February that we will continue drilling in the Deepwater and we continue at a disciplined pace, though.

Okay, thanks, Phil.

That does conclude our question-and-answer session. At this time, I would like to turn the call back over to Ken Matheny for any additional or closing remarks.

Okay, Patty, thank you very much and thank everybody for participating in the call. I really don't have anything more. We look forward to bringing you up to date on our year-end results at the end of January. Thank you very much.

Thank you for your participation. You may now disconnect.