馬拉松石油 (MRO) 2006 Q3 法說會逐字稿

Good day everyone, and welcome to this Marathon Oil Corporation third quarter 2006 earnings conference call. As a reminder today's call is being recorded.

For opening remarks and introductions I would like to turn the call over to Mr. Kenneth Matheny, Vice President of Investor Relations and Public Affairs. Please go ahead, sir.

Okay well thank you very much, Linda and I too would like to welcome all of you to our third quarter 2006 earnings conference call. As a reminder for all the telephone participants you can find the synchronized slides that accompany this call on our website www.marathon.com. 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, Dave Roberts, Senior Vice President of Business Development, Gary Heminger, Marathon Executive Vice President and President of our Refining Marketing Transportation Organization, and Garry Peiffer, Senior Vice President of Finance and Commercial Services for the downstream organization.

Slide number two 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 10K for the year ended December 31st, 2005, in subsequent forms 10Q and 8K, cautionary language identifying important factors but not necessarily all factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

If you'll now turn to slide number three. Net income for the third quarter was just over $1.6 billion versus $770 million in the third quarter of 2005. Net income adjusted for special items was $1.54 billion versus $797 million in the third quarter of 2005.

If we move on to slide number four, the substantial increase in net income adjusted for special items year-over-year was driven by positive price and volume variances in the upstream segment and the continued strength in our downstream business. As a reminder this is the first year-over-year comparison where we have owned 100% of the downstream business in both quarters. These positive factors were significantly offset by almost $800 million in higher income taxes.

If we move on to slide number five, adjusted net income for the third quarter of 2006 was slightly higher than that realized in the second quarter of 2006. Improved downstream earnings were largely offset by lower prices in sales volumes in the upstream. Volumes available for sale were relatively flat when compared to the previous quarter with the timing of liftings creating the variance in recorded sales volumes. Remind you that a reconciliation of net income adjusted for special items to net income is included on slide three. Please refer to slide two for a discussion of the use of this nonGAAP measure.

We now look at slide number six. Third quarter per share net income adjusted for special items on a diluted basis was $4.30 a share, a $0.14 increase from the second quarter. There were approximately 359.4 million weighted average shares outstanding during the quarter on a diluted basis. And through the third quarter, we have repurchased approximately 14.4 million common shares at a cost of just over $1.1 billion. We expect to complete approximately $1.5 billion of our authorized $2 billion share repurchase program during 2006 with a balance to be repurchased in 2007. At the current share price in the mid to upper $80 range, we would expect to repurchase another 4 million shares during the fourth quarter which would reduce the weighted average diluted share count to approximately $355 million for the fourth quarter.

As shown on slide seven, upstream segment income decreased $87 million over the second quarter results, largely a result of lower sales volumes and realized prices for liquids and natural gas as well as higher exploration expense. This was partially offset by lower income taxes and lower DD&A. The lower liquid sales volumes were mainly attributable to the timing of liftings in the U.K. and in Equatorial Guinea. The lower gas sales were related mainly to lower seasonal sales in Europe. Production available for sale averaged 354,000 barrels of oil equivalent or BOE per day essentially unchanged from the second quarter.

During the, pardon me, during the third quarter, we produced and lifted approximately 2.8 million barrels in Libya that were not included in our previous Libyan production guidance of 40 to 45,000 barrels per day for the year 2006, but were included in our third quarter production guidance. This represents 100% of the barrels owed to our account upon return to Libya and the lifting of these barrels had a significant impact on our third quarter reported earnings which will not be repeated in subsequent quarters. Including the Libyan barrels just discussed, we anticipate production available for sale for the year to average between 360,000 and 370,000 barrels of oil equivalent per day in line with our previous guidance. For the fourth quarter, we expect production available for sale to average between 350 and 370,000 barrels of oil equivalent per day. And I'll remind you that our actual sales could differ from these ranges depending on the timing of international crude liftings.

Slide number eight shows domestic upstream income of $218 million, a decrease of $25 million from the second quarter. Domestic liquid realizations increased $0.57 per barrel compared to an $0.18 decrease in the NYMEX prompt WTI, primarily a result of natural gas liquids realizations outperforming WTI during the third quarter. U.S. natural gas realizations increased slightly from the second quarter as did realizations for our lower 48 gas, while the bid week natural gas price was slightly weaker. Realized prices were higher due to improved basis differentials for gas sold in the mid-continent and in Texas.

As shown on slide Number nine, there were a number of factors contributing to the net decrease in domestic upstream income, but the largest single factor was the lower liquids volumes previously referenced.

Turning to slide number 10. Total domestic upstream expense excluding exploration expense was $1.32 per barrel of oil equivalent higher than the second quarter, primarily as a result of higher field level costs associated with work over expenses and higher indirect costs. And as shown on slide number 11, domestic upstream income per barrel of oil equivalent decreased $1.27 quarter-over-quarter in line with the overall increase in expense.

Moving to the international upstream in slide number 12. International upstream income decreased $62 million to $354 million. This was mainly due to lower volumes and lower realized prices somewhat offset by lower income taxes. The lower natural gas price realizations were a result of lower volumes of gas sold in Europe relative to the volume of significantly lower price gas in Equatorial Guinea.

Slide 13 shows the impact of these price and volume variances along with the offsetting lower income taxes on our international income. We also had higher exploration expense, the result of an acreage relinquishment and a dry hole, both in West Africa. And lower DD&A expense as a result of the timing of U.K. crude oil liftings.

As shown on slide 14, total international upstream liquid sales volumes decreased approximately 6% largely a result of the timing of liftings in our international operations partially offset by additional Libyan volumes. Natural gas sales decreased approximately 29% primarily due to seasonality in the European market. International upstream expense excluding exploration expense was relatively flat on a per barrel of oil equivalent basis. And slide 15 shows that international upstream income decreased approximately $1.20 per barrel of oil equivalent largely a result of the higher exploration expense.

Moving on to the downstream business in slide number 16, Refining Marketing and Transportation's third quarter segment income was a record and totaled just over $1 billion, compared to $473 million in the third quarter last year. Because of the seasonality in the downstream business, I will compare the third quarter 2006 results against the same quarter in 2005. The most significant factor contributing to downstreams' improvement this quarter over the same quarter last year, was that our average refined product realizations increased more than refined product spot prices included in the WTI 6-3-2-1 6321 metric in the third quarter of 2006 versus the third quarter of 2005. This resulted in a positive financial benefit versus the value change indicated by the spot market refined product prices used in that same 6-3-2-1 metric.

In addition, our Refining Wholesale Marketing gross margin was enhanced by favorable realizations on our ethanol blending program and like products purchased for resale in the third quarter 2006 versus the same quarter last year. Part of the ethanol enhancement resulted from marking to market derivative contracts we sold to requote the fixed price we have under ethanol contracts that will be in place for about two years. These fixed price contracts represent about 20% of the ethanol we plan to blend over this period of time.

Crude oil and other feedstock costs were also relatively lower than the change in WTI prices during the quarter versus the same quarter last year primarily due to the effects of declining crude oil prices. In addition, the widening of the sweet-sour differential this quarter versus the same quarter last year also reduced our crude oil cost versus the change in the price of WTI crude. Due to the decrease in crude oil prices during this quarter we had a positive crude, pardon me, a positive crude in-transit price effect of $53 million versus a negative $37 million in the same quarter last year for a $90 million improvement quarter-over-quarter.

Our refineries ran very well during the quarter, averaging 1.031 million barrels per day of crude oil throughputs, and 1.249 million barrels per day of total throughput, which is a record for total throughputs for a quarter. Because of the expansion of our Detroit refinery late last year and the solid operating performance of all of our refineries, we were able to process about 5% more total refinery inputs as well as generate larger volumetric gains compared to the same quarter last year. Our crack spread and derivative trading activity was about $8 million positive in this quarter versus about $55 million negative in the same quarter last year, thus improving earnings quarter-to-quarter by about $63 million.

Since we have elected not to use hedge accounting for our downstream, all of our derivative activities are required to be mark-to-market by FAS 133. Since prices fell during the third quarter, marking-to-market all of our other derivatives resulted in a positive impact versus the same quarter last year. We have consistently used derivative instruments to manage price risk and to protect the carrying value of inventories. This includes crude oil, refined products and ethanol as well as other commodities. In periods of rapidly changing prices, the gains and losses from this derivative activity can be large. What should not be overlooked is that most of the gain or loss on this derivative activity is offset by changes in the value of the underlying fiscal commodities we are price protecting.

Our Refining and Wholesale Marketing gross margin in the third quarter 2006 included a pre-tax gain of $384 million related to derivatives while the same quarter last year had a pre-tax loss of $271 million, a variance of $655 million. However, including the gains and losses from the physical commodities underlying these contracts, we estimate the actual pre-tax income effect between the two quarters was approximately $150 million.

Partially offsetting these positive factors was the decline in the WTI 6-3-2-1 crack spreads during the third quarter versus the same quarter last year. The WTI 6-3-2-1 crack spread which includes three barrels of gasoline, two barrels of low sulfur fuel oil, and one barrel of 3% number six fuel oil better approximates our total production slate than the traditional WTI 3-2-1 crack spread. On a 2/3 Chicago, 1/3 U.S. Gulf Coast basis, the WTI 6-3-2-1 declined during the third quarter falling to $8.50 per barrel compared to $10.70 per barrel in the same quarter last year.

We move on to slide number 17, Speedway SuperAmerica, what we call SSA, increased gasoline and distillate and sales 42 million gallons or 5% quarter-over-quarter. SSA same-store gasoline sales volumes were up 4.9% with SSAs retail gasoline prices averaging $2.65 per gallon during the quarter compared to $2.45 per gallon in the same quarter last year. And SSA's merchandise sales on a same-store basis increased 6.7% compared to the same quarter in 2005. SSA's gross margin for gasoline and distillate was $0.141 per gallon in the third quarter 2006 up nearly $0.02 per gallon from the margin realized for the same period last year.

Slide number 18 provides a summary of segment data along with a reconciliation of net income. I will not go through this item-by-item other than to point out three items of interest. First, the Integrated Gas segment had a loss of $2 million during third quarter 2006 compared to income of $17 million in the second quarter. This decrease was partially a function of down time at the AMPCO methanol facility while it was undergoing a turnaround and subsequent compressor repairs.

Second, unallocated administrative expense was down $21 million to $78 million in the quarter, primarily a result of cost related to the disaster preparedness programs in the second quarter. And third, net interest and financing costs remain positive at $7 million for the quarter due to strong interest rates on cash balance and higher capitalized interest.

Slide 19 provides selected preliminary balance sheet and cash flow data. Due to slightly decreased cash balances, cash adjusted debt went up slightly and the cash adjusted debt-to-capital ratio at September 30th, 2006, went from 5 to 6%. I'd just like to remind you that the cash adjusted debt balance includes approximately $518 million of debt and continues to be serviced by U.S. Steel. Year-to-date, preliminary cash flow from operations was approximately $3.7 billion and preliminary cash flow from operations before working capital changes was approximately $4.8 billion.

Slide 20 provides information from prior periods as well as guidance for the fourth quarter and the full year 2006. I would now like to turn the call over to Clarence Cazalot.

Thank you, Ken. A lot of the attention today has been focused on the impact of derivatives in our downstream business and I hope that Ken's comments and some of your follow-on questions will help clear up some of that confusion. But I want to make sure that our strong operational performance isn't overshadowed by that, and I want to point out something Ken said a moment ago, looking at our refinery runs, we're up 5% year-on-year. And it isn't simply running more throughputs through our refineries. That's coupled with some very smart commercial decisions that are being made by our downstream people in a very volatile market. And our upstream sales from continuing operations are up 26% year-on-year, even when you exclude the one-time makeup volumes in Libya.

So, while we continue to focus on our current assets, our current business, executing on and advancing our major projects, we want to make sure we take the opportunity to update you on some of the new opportunities we're pursuing. So in that context, I'd like Dave Roberts to update you on Canadian oils sands, the status of that, and the status of EG LNG Train 2. And then I'd like Steve Hinchman to update you on the Bakken play in the Williston Basin. So Dave?

Thanks, Clarence. I'll start with the Canadian oil sands. As you know, we've been engaged for some time in unilateral discussions with key players in this sector. We now believe the best way to achieve a full recognition of the value of Marathon's downstream offering to Canada's bitumen producers is to engage in a robust and disciplined process that will include a number of potential partners. We continue to believe in integrated project comprised of a reserves to product solution is the highest value outcome for Marathon and its potential partners. We expect to make an announcement regarding our process in the coming day.

Obviously, we've watched with interest the developments between EnCana and ConocoPhillips, and we believe this supports our premise of the value of a fully integrated solution between upstream and downstream partners. We continue to believe Marathon is well positioned to provide the downstream solution to a number of potential Canadian producing partners based on our world class pad two refining assets.

With respect to EG Train 2, we continue to be encouraged by the news flow from both Nigeria and Equatorial Guinea regarding the progress of bilateral negotiations between the countries to allow EG LNG to become a regional gas hub. In addition, similar activities with Cameroon are underway. An exploration potential does remain in EG creating a robust supply outlook for EG LNG. As you know, we announced entry into FEED for Train 2 earlier this year and continue to make progress in that process as well as preparatory activities on the Bioko Island side itself. We and our partners, Sonagas, Mitsui and Marubeni are fully engaged with a number of potential gas suppliers in the region and expect good progress towards concluding GSAs in 2007.

In summary, technically, we're in a very forward position and our commercial activities are gaining momentum. We continue to see FID as likely in the 2007 to 2008 timeframe with LNG deliveries from Train 2 commencing in 2011 or perhaps 2012 depending on these intergovernmental treaty progress. It's worth noting that once the treaties with Nigeria and Cameroon are concluded the full potential of EG LNG can be realized which may include the addition of multiple LNG trends. And with that I'll turn it over to Steve Hinchman.

Thanks, Dave. Hello, it's early. I know that there is interest in how we're progressing with our evaluation and development of the Bakken Shale in North Dakota. We're currently operating two rigs, beginning the preliminary evaluation of our nearly 200,000 acre position. So far, we have two Company operated and one operated by other well on production. Two of the wells are located in Dunn County and one of the wells is located in Williams County. Initial gross rates were over 600 barrels of oil per day with a GOR of about 720 standard cubic feet per stock tank barrel. The one month average rate is between 300 and 325 barrels of oil equivalent per day, which is right in line with the expectations that we've had from production out of the Bakken Shale. We're currently stimulating one well and we're drilling two wells at this time, one in Williams County and one in Dunn County.

We expect to receive five new build drilling rigs beginning in March and running through September of 2007, so by the fourth quarter of next year, our operated rig fleet will reach our target number of between seven and eight rigs. So our 200,000 acre position exposes us to 300 well locations with nearly 100 million barrels of potential resource with additional infill likely. By maintaining our active rig fleet between seven and eight rigs, we should build production to around 20,000 barrels a day by 2012. It's still early, but so far, everything is on track and meeting expectations. With that I'll turn it back over to Ken Matheny.

Okay, thank you very much, Steve. I'd like to take this opportunity to remind all the listeners of our fast approaching analyst meetings which we will hold on November 29th in New York and on November 30th in London. If you would like to attend one of these meetings with Senior Management and have not already done so, please call Bonnie Chisum at 713-296-4171. Before we take questions I'd like to remind you that in the interest to fairness to all those wishing to ask a question, please limit yourself to one question and a related follow-up. You may then reprompt if you have additional questions. Linda, we're ready to open up the line.

Thank you, gentlemen. [OPERATOR INSTRUCTIONS] We'll go first to Robert Kessler of Simmons & Company.

Good afternoon. You might have seen this morning the announced diver strike in the U.K. I was wondering if you had any implications for [Alpine] next door and Norway.

This is Steve Hinchman. No. We really at this point in time have pretty much completed all of the diver related operations, so the strike should not have any significant impact on our operations here forward.

Good news, thanks, Steve.

Moving on to Jennifer Rowland of JP Morgan.

Hi, good afternoon. It's Kate Lucas for Jenn Rowland. You mentioned in your press release that your Refining and Wholesale Marketing gross margins were favorably impacted by your ethanol blending program. You may have touched on it in your comments, but could you just expand a little bit on that and quantify the impact and maybe the outlook going forward?

Yes. This is Garry Peiffer. In the third quarter, we benefited from a couple of things. First of all, we entered a number of long term contracts about a year ago that allowed us to buy ethanol at very favorable prices. And the other thing that had about, about $100 million effect on us in the third quarter versus the third quarter last year, was in order to lock in some ethanol supply for the coming couple years with all of the renewable fuel standard that has been past last year, we've entered into a number of long term contracts. About 20% of what we expect to blend, we've entered into fixed price, long term contracts.

In order to protect us against an adverse price move, we've gone out and essentially hedged those contracts so about $100 million of the effect in the third quarter versus the third quarter last year that we benefited this quarter, was from those long term contracts we've entered to buy around 20% of what we expect to blend in the way of natural gas on fixed price contracts so-- ethanol, excuse me, fixed price ethanol over the next two years.

Okay, and if I could just follow-up on your ethanol program. Could you give us a little color around the agreement for the joint venture with Andersons, a sense of the capital required. And then do you expect getting all of your ethanol volumes going forward from the joint venture?

No. Kate, this is Gary Heminger. Put this in context. All our demand for ethanol based on where we see the year ending this year and going into next year, is probably going to be around 800 million gallons a year, upwards to a billion gallons a year depending on how the market moves. This-- we just announced the first plant that we've signed a definitive agreement with the Andersons on. We have not announced exactly where that plant will be located as we're finalizing some air permits. However it is our long term strategy that we're only going to order-- own a small portion of our true needs in ethanol blending.

A couple different things. First of all, we believe the ethanol market will continue to grow, but this gives us tremendous intellectual knowledge in the ethanol market both from the grain side and from the finished product side, that will help us in our long term strategy of acquiring ethanol.

All right, thanks very much.

Moving on to Neil McMahon of Bernstein.

Hi, good morning. Two questions. The first is looking at your last balance sheet, it looks like you took some impairments on your goodwill and intangibles in the second quarter and I was wondering if those were related to either the Piceance basin or to Libya. Maybe you could just bring us up to speed with what the situation was like in the third quarter, maybe also comment on what the activity is looking like in the Piceance basin.

Yes, Neil, we actually didn't even complete the transaction in the Piceance basin until July, but I think what you're referring to, we sold our Russian operations in the second quarter and there had been goodwill associated with that, and so because of that sale we had to take that goodwill associated with those assets off the balance sheet. And there are no impairments on Libya either.

Okay, great. And maybe just a comment on the Piceance basin activity given the gas prices?

Yes, Neil, we're looking to bring in four new build rigs and we won't-- the first delivery we'll see will be in October of 2007, and then through probably May of 2008. So at this point in time in Piceance, we're really in the planning stage and we won't begin our drilling activity until later, later next year.

And it was mainly a question around that. Are you going to change any of your activity over the next 18 months, two years based on what you're seeing today?

No. I think that we look at a longer term gas price and the Piceance is still an attractive project for us to invest in down to $5 Henry Hub gas price.

We'll take our next question from Paul Sankey of Deutsche Bank.

Hi, guys. Just several quick ones for me. Firstly, could I just clarify did you just say that you're going to make a major announcement on Canadian heavy oil within the coming days?

Paul, this is Dave Roberts. What I said is that we're going to make an announcement on the process that we're going to use to get to an end game on the Canadian oil sand.

Okay, I understand and that's coming within the next few days?

In the coming days, yes.

Okay, great. Thanks that was, I couldn't quite hear what you said but thanks for that. If I could switch to -- let's stick on the downstream in the U.S. for a little bit. Firstly, the capacity utilization you've exhibited here as a record high, is this a ratable level of capacity utilization or was it a special quarter, or could we expect it yet to go higher in terms of what sort of throughputs you achieve?

No. I would say, Paul, that the way we operated in the third quarter is how we should be able to operate, barring any unforeseen circumstances going forward. Understanding that in the third quarter, depending on how we run asphalt, depending on some of the crudes and some of the lighter ends you can run, we can at times get a little more throughput with some of those lighter crudes. But we would expect year-on-year, and it all depends on where the margins are in the marketplace and what we try to run.

I think that's intuitive, but year-on-year, the performance that you've seen year-to-date, we would expect, first of all, it's much in line with last year and we would expect to continue on that path going forward.

Great. Thanks and further, to your derivatives that you mentioned, derivative gains, could you talk a little bit about how much value at risk you put or how you manage the risk of what's obviously been this quarter a very successful program? Thanks.

Yes, Paul. This is Garry Peiffer. I don't think we necessarily look at it from a value-risk standpoint since typically, most of what we're doing is hedging our physical commodities, whether it be the crude oil purchases which we have every day, the million barrels or so a day of crude that we buy, the-- and in the third quarter, the crude purchases was a big part of the total derivative effect with the price drop which we experienced late in the, late in the quarter.

As well as the fact that we were pretty heavy on inventories going through the second and third quarters with the potential for hurricanes plus the market being in contango, the market was essentially paying us for storing inventory, so we look at it more as we have a physical commodity risk that we brought in hedge and we basically have consistently done that throughout our existence, since we created MAP and even before that. So it's been a consistent program of trying to hedge our risk, albeit the crude purchases or excess inventories primarily.

And Paul, this is Gary. Let me just put this into further context. Our normal operating course of business, that 671 that Ken mentioned in his speech, about $520 million is just the way the markets changed this year versus the markets last year being offset by physical, so that is normal operating course of business movement in the marketplace. So it's about $150 million as Ken stated that really was the effect, most of that coming from our ethanol program, so I really just want to put that into perspective.

Moving on to Mark Flannery of Credit Suisse.

Yes, hi. I would just like to follow-up on that, which is do you have any-- if we look forward for planning purposes for these derivative gains and losses, do you have any rules of thumb that we can use or anything to take some of the noise out of these numbers? I appreciate that some of the gains and stuff is offset by the physical, but when you choose to report a very big number like this, it inevitably grabs a lot of peoples' attention so can you help us with some forecasting?

Well, I think that in the past, Mark, it's Garry Peiffer again, it's been relatively minor with the exception of some trading opportunities and some crack spreads which we've sold forward in the past, and I guess going forward assuming that we don't have big price swings we would expect all of this derivative impact to be relatively minor, even excluding the normal course of business-type of things.

Because as Gary pointed out, even though the-- if you just look at the derivatives and the paper effects, most of that was offset by physical effects that we don't report on separately except through the R&M margin in combination with the derivative effect. So I would say it's going to be relatively minor going forward.

Okay and I guess my follow-up is on the topic of one-time items. Any view on how much that extra 2.8 million barrels of Libyan production added to the E&P bottom line?

For the--in the third quarter, I think it's around 70 million.

On a net basis?

Net income basis, yes.

Great. Thanks very much.

And moving on to Paul Cheng of Lehman Brothers.

Hi, guys. Just wondering, on the 384 million on the hedging gain, how much of them is contributed by the P-plus scheme?

Paul, this is Garry Peiffer. I don't have it broken out by P-plus, but most of the 385, about 245 million of it was related to crude oil related activities and that would be the P-plus program as you noted. Plus the fact that we had, we built inventories in the second and primarily in the third quarters to ensure we had sufficient crude, should there be a disruption in the system , as well as the market was in contango, so in total about 250 of the 385 was crude related.

I see, great. Maybe this is for Steve. EG, Equatorial Guinea I think recently they have announced they're going to raise the royalty rate or that their production tax in the country. I'm wondering have you guys been contacted or that you said just under [inaudible] and there is nothing to do with the R&G?

Paul, this is Clarence. Again, I think we've seen the same press reports but we simply aren't going to comment on future business decisions or relationships with our business partners.

Clarence, can you confirm that you're being contacted by the government yet?

No, simply not going to comment on that, Paul.

Okay, thank you.

And [Sineal Jugwanie] from Citadel has our next question.

Yes, hi, guys. My question was around this oil sands potential. How much do you think the EnCana, Conoco Phillips will prove to be a precedent for future deals? Is that being considered a benchmark do you think in your negotiations, fully recognizing that pretty much every deal will be pretty idiosyncratic as well?

Sineal, this is Dave Roberts. I think your last comment is the correct one. Every deal has got to be balanced on its own merits, and we obviously look at the fact that there will be a lot of attention paid to that deal, but by the same token, I'd point out that we have a lot of confidence in the value of our downstream assets and the value that Marathon can deliver to a deal, and we expect to be able to deliver this value created to our shareholders.

The reason I ask is because I think the exchange ratio there ended up being about one barrel of oil sands production on a daily basis in exchange for I think about one barrel of refining or approximately one-to-one. And I just wondered if that's kind of a rough ratio that we should be thinking about, at least as a ballpark figure?

I don't think we will speculate on what our deal is going to look like.

All right, thank you.

[OPERATOR INSTRUCTIONS] Moving on to Mark Gilman of Benchmark Company.

Folks, good afternoon. I wonder if we could get a bit of an update on Alvheim? It seems the schedule might have slipped just a little bit. Was looking for what you think total development costs are going to come in at, and what kind of DD&A rate we would be looking for. And if you could address the same issues with respect to [Vooland] which you recently sanctioned I'd appreciate it.

Yes, Mark, this is Steve Hinchman. On Alvheim, we're around 73% complete right now. We basically completed most of the sub-sea activity, and the top sides should be mechanically complete in December, so we hope to put the vessel out some time in January. And so we would expect to still come on production in the first quarter of 2007, so if there's a slippage, it's within a month of what our original target has been for that project since inception.

The development cost at Alvheim, is around $7.42 a barrel, so over time, I'd expect that would be where our DD&A will average out at. And just a correction on [Vooland]. We have submitted our PDO in [Vooland] in September and we'd expect to have the PDO approved here in November, and [Vooland's] total development cost is going to roughly be around $7.50 a barrel.

Thanks very much, Steve.

You bet, Mark.

And John Herrlin of Merrill Lynch has our next question.

Yes, hi. Two quick ones. With the integrated [Putuman] operations would you be willing to swap out your refining capacity like EnCana? Maybe I missed that but I was wondering if you'd do the same sort of thing to get direct upstream exposure?

John, this is Dave Roberts. I think we'd consider a variety of potential transaction types. But again, we believe a fully integrated reserves-to-product venture is the most value accretive type deal to do in this asset base.

Okay. With EGA, you mentioned becoming more of a regional gas hub. Would you be able to take no flare Nigerian gas or just things that are close by in the region or what? What's your thinking with respect to that?

Well, I think we're looking at taking gas that's nearby. Obviously we wouldn't talk about going too far afield but there are substantial gas reserves available within proximity of Bioko Island that we could access in Nigeria.

Yes, true. No doubt. Thank you.

And it appears we have a follow-up question from Neil McMahon of Bernstein.

Hi, I think it's a question for Gary, really. Could you tell me what your storage situation was during the third quarter? It sounds like you were running pretty full inventories and really where it is today? And on top of that, what are your views going forward in terms of playing the contango that's in the market and I think is getting as big as over $6 today when you look at six months? If you could just talk through that that would be great.

Yes, first of all, Neil, on the-- our inventories over the summer. It is our normal practice in all of our Gulf Coast refineries to have a significant amount of inventory just to protect ourselves from any high water or high winds so operationally to protect yourself. As well as our, when you look at the refined product around all of our water-based and Gulf Coast-based terminals to protect ourselves from there as well. So it is typical in the third quarter that we carry high inventories, however, and you're right. Looking at today's contango in fact it might even be upwards of $7 looking at the contango, and we will, as Clarence said in the outset, we will try to make commercially good decisions on where we store crude, and when we store crude to take advantage of that contango in the marketplace.

So is your storage still pretty much full and your hedge going forward?

Well, we're still we're just coming off of the back end of the hurricane season, so we have been pretty full and have enjoyed a very strong contango throughout the entire fall, so yes, I would say that we are pretty full at this time.

Great. Thank you.

Yes.

And Nicci Decker of Bear Stearns has our next question.

Oh, good afternoon. Just some little ones on the upstream. First of all, the two wells in Angola that have reached TD, are those on block 31?

Nicci, this is Phil Behrman. Those are on block 32.

On block 32, okay, thank you. And in the Gulf of Mexico, the black water, when do you expect that to reach TD and what is the resource estimates and maybe you could talk about your drilling plans in the Gulf of Mexico for 2007.

Sure. Nicci, we haven't given resource estimates for a lot of these wells for quite awhile and so we probably won't do that today, However, that well is in block 246 in Green Canyon. We're targeting a conventional play, a miocene and younger play out there. That well should reach total depth roughly around year end or into first quarter, depending on drilling conditions. Also in 2000, well actually into 2007, we started this year the Stones appraisal well. Rig will come back and finish that well in first and second quarter of 2007, and then we have an additional well or two planned for 2007 in the Gulf of Mexico.

Are those Marathon operated well cat wells?

They will vary from Marathon to partner-operated.

Thank you.

And Paul Cheng of Lehman Brothers has a follow-up.

A quick one. Gary? When [inaudible] talking about 4.9% year-over-year same-store sales gain for the gasoline, is that for the store open for more than 12 months or just in [echo-to-echo] here?

Yes, Paul. That's 12 month like-versus-like and we take out any changes if the store happened to be closed for any reason or any road construction for any reason, we don't count that as store, so that's straight up like-versus-like.

Thank you.

And Mark Gilman of Benchmark also has a follow-up.

Yes, guys. I think Ken mentioned a dry, West African dry hole in the third quarter. I wonder if you could specify where that was?

Yes, Mark. This is Phil Behrman. We can't specify it anymore than West Africa at this point in time. We just don't want to get out in front of the operator and so we have to let them handle the first indications.

Okay, so I can infer it's nonoperated? Fourth quarter production available for sale, the international liquids number from 25 to 135. It seems a little bit low to me taken into consideration the absence of the Libyan makeup but also the expectation that North Sea liquids will probably come back a little bit post-maintenance in the period. Am I missing something with that number?

No, Mark. We didn't have, there's a little bit of maintenance that was done primarily on Foinhaven, but no, there's nothing unusual with that number, so I'm not exactly sure what you're getting at.

Well if I just take 30 out of the third quarter, I get down to, no to 140, and obviously the mid-point, you're 10 to 15 below that.

We're-- I'm sorry, Ken. The guidance was --

The guidance was 125 to 135.

125 to 135, yes, and I'm trying to, I can't think of anything there. We'll continue to have some declines in our Brae liquids, but nothing unusual there.

Okay, Steve. Thanks.

And gentlemen, there are no further questions. Mr. Matheny, we'll turn the conference back over to you for any additional or closing remarks.

Okay thank you very much, Linda, and I'd like to thank everybody for their questions. And one more reminder, our analyst meeting is coming up the end of November, the 29th in New York City, the 30th in London, so we look forward to seeing a number of you there. Thank you very much.

That does conclude today's conference. We do thank you for your participation and have a wonderful day.